Petrohawk Energy Is Rolling the Dice on Gas-Shale Plays

(MoneyWatch)  Petrohawk Energy confidently predicts that the $5 billion spent on leasehold acquisitions and drilling projects (in just the last two years) for promising U.S. shale plays will offer attractive long-term production and profit growth potential for many years to come. A bad bet, say outside observers, arguing that the natural gas producer's estimated-reserves-to production ratio of almost 16 years is not only overstated, but that projected shale gas numbers, known as estimated ultimate recovery (EUR) rates, are rooted in untenable flow rates.

Petrohawk Energy's (HK) experienced significant growth in production and reserves in 2009, said chairman and chief executive officer Floyd Wilson on the fourth-quarter 2009 conference call. Proved reserves (98% natural gas) grew 122 percent to 2.75 trillion cubic feet equivalent (Tcfe), most of which was added through drill-bit activity in its Haynesville Shale. The company exited 2009 producing approximately 600 Mmcfe per day, up from an approximate exit rate of 366 Mmcfe per day in 2008.

The volume of gas resources claimed by operators is not in dispute. Evidence presented at the 2009 meeting of the Gulf Coast Association of Geological Societies (GCAGS) held in September 2009 suggests, however, that formation damage during fracture stimulation treatment -- cracking the shale open to expose the gas pockets -- in effect, reduces reservoir performance and resultant economic viability:

Ductility of the reservoir and its subsequent compaction as pressure is reduced suggest that ultimate recoveries may be sub-commercial. Formation damage from the loss of millions of gallons of treatment water to the reservoir is another concern. ~ Arthur Berman & Lyndon Pittinger, World Oil, October 2009 issue

The company contends it is achieving efficiencies in drilling operations, mainly driven by a continued improvement in Rate of Penetration (ROP), said president and chief operating officer Dick Stoneburner on the conference call. He then offered up as evidence the progressive decrease in the number "spud to spud" days during the year: The number of days to ready a well for production decreased 23 percent during the year to 54 by the fourth-quarter. The company anticipates that completion rate will decrease further to 42 days during 2010.

"This decline in the drilling days translates directly to a reduction in cost," said Stoneburner, "with the average cost per foot decreasing by almost 25 percent (to $271/foot) during 2009." Petrohawk is currently operating 17 horizontal rigs in the In the Haynesville Shale, principally in Northwest Louisiana and East Texas. Of the $1.45 billion drilling budget for 2010, $900 million is being set aside for Haynesville, with plans to spud between 110 and 120 wells.

Berman and Pittinger are forecasting sub-commercial average EUR for the Haynesville Shale because of the extreme rates of production decline: "Most wells with an initial production (IP) of more than 10 MMcfe/d have a decline rate of 25% per month."

Contrary to the predictions of its skeptics, the company insists that its current Haynesville well-curve of 7.5 Bcfe can support viable EURs, assuming first-month average IP of 16 MMcfe/day and first year decline of 82 percent. Additionally, 80 percent of the total EUR, or 6.0 Bcfe, will be produced in the first ten years.

The analysts concede that limited production histories in Haynesville -- Petrohawk's oldest well has been in operation less than two years -- make it difficult to ascertain actual decline rates. Nonetheless, using more mature plays (such as the Barnett Shale in Texas) as a representative analog, the geological consultants caution that analysis of historic well-decline curves do not support the long-term optimistic view of Petrohawk's management team - that the natural gas can be profitably extracted up to, on average, 32 years (according to data available in regulatory filings)!

Berman remains steadfast in his view that the Haynesville Shale -- despite company promulgations to the contrary -- will not approach a commercial threshold until both gas prices AND per well reserves increase:

With cost per well of $8.5 million to $9.0 million, breakeven (Net Present Value = 10 percent) will require minimum per-well reserve volume of 2.5 Bcfe and a netback gas price of about $9 per MMBtu (Henry Hub).

The spot price closed at $5.46 per million British thermal units on February 9.

Chief operating officer Stoneburner chimed in on the conference call update that new production practices "being tested" (such as novel, multistage lateral fracturing techniques) could flatten decline curves, lower finding and development costs, and add to incremental reserves.

Petrohawk (and other E&P company) supporters deride the conclusions of Berman and Pittinger, alleging their decline method calculations are technically flawed and inherently biased toward under-estimate recoveries. Vertical depths plunging down to 13,000 feet, lateral drilling extending beyond 6,000 feet, and shale formations in some zones as much as 300 feet thick -- even a blind dog knows when its raining.