Petrohawk announced its third quarter 2010 financial and operational results and provided a preview of 2011 capital spending plans and production guidance.
Third Quarter 2010 Highlights
Total production for the quarter was 60.1 billion cubic feet (Bcf) of natural gas, 290 thousand barrels (MBbls) of oil, and 186 MBbls of natural gas liquids, or 63.0 billion cubic feet of natural gas equivalent (Bcfe) of which 95% was natural gas. Petrohawk's production was 3% crude oil and 2% natural gas liquids.
Petrohawk's average realized natural gas price for the quarter was $5.19 per Mcf, which included a realized gain from natural gas derivatives of $0.99 per Mcf. The Company's average realized price for natural gas, before the impact of realized derivative gains, was $4.20 per Mcf, a 34% increase in the realized natural gas price compared to the third quarter of 2009 and 96% of the average NYMEX price for the quarter of $4.38 per Mcf. Petrohawk's average realized oil price for the quarter was $75.15 per Bbl, which included a $2.19 per Bbl of realized gain from oil derivatives. Before the impact of realized derivative gains, the average realized price for oil was $72.96 per Bbl, or 96% of the average NYMEX price for the quarter of $76.20 per Bbl and a 13% increase compared to the third quarter of 2009. Natural gas liquids were sold at an average of 46% of the per barrel NYMEX price of oil.
Cash flow from operations before changes in working capital (a non-GAAP financial measure; see Condensed Consolidated Statements of Cash Flows for a reconciliation to net cash provided by operating activities) was $188 million, or $0.62 per fully diluted common share, compared to $163 million, or $0.54 per fully diluted common share, reported for second quarter 2010 and $152 million, or $0.52 per fully diluted common share one year ago. The Company benefited from a strong and high volume of particularly natural gas hedges in effect during the quarter. Realized hedged receipts of $60.3 million were reported for the third quarter. Cash flow was negatively affected by $39 million in cash payments, reported as non-recurring interest expense, related to the early tender of long term debt that was refinanced at a lower interest rate during the quarter. After adjusting for selected items, primarily related to the non-cash impact of derivatives and the non-recurring interest expense, net income for the quarter was $39.9 million, or $0.13 per fully diluted common share, versus $31.2 million, or $0.11 per fully diluted common share one year ago (see Selected Item Review and Reconciliation table for additional information). Before excluding selected items, net income of $99 million was reported for the quarter, or $0.33 per fully diluted common share.
Lease operating costs were a reported at a record low of $0.25 per million cubic feet of natural gas equivalent (Mcfe), or $15.8 million, primarily driven by increased low-cost production from the Haynesville Shale. Taxes other than income were reported as a credit of $3 million, affected by the timing of certain severance tax refunds. Interest expense included certain non-recurring payments related to a major debt refinancing which closed during the quarter; approximately $775 million in senior notes due in 2013 with an interest rate of 9-1/8% were refinanced through the issuance of new senior notes issued at par with an interest rate of 7-1/4% and a maturity of 2018.
As of November 1, 2010, the borrowing base under the Company's revolving credit facility has been increased to $1.75 billion for oil and natural gas assets, a 75% increase over its previous borrowing base. At the end of the third quarter, Petrohawk's outstanding balance on its revolving credit facility was $129 million.
In addition, the Company has begun the marketing process for the potential sale of its natural gas and midstream assets in the Fayetteville Shale. Bank of America Merrill Lynch is acting as advisor on the sale process. During the third quarter, net production from the Fayetteville Shale averaged 95 Mmcfe/d.
The Company is adjusting its 2010 capital budget to $2.55 billion, from the prior amount of $2.13 billion. This increase is largely driven by service cost inflation, specifically pressure pumping services both in the Haynesville Shale and the Eagle Ford Shale, and a much larger amount of non-operated drilling than was estimated in early 2010. Petrohawk estimates that 2010 and 2011 capital spending will be amply covered by a combination of cash flow, prior non-core asset sales and capacity under its $1.75 billion revolving credit facility. Additional non-core asset sales may add to this already substantial liquidity.
Full year 2010 production guidance is increased to between 665 and 675 Mmcfe/d, indicating 58% organic growth over 2009, with divestitures taken into account. Fourth quarter 2010 production guidance is increased to between 740 and 760 Mmcfe/d, indicating 9% quarter over quarter and 33% year over year growth, not accounting for approximately 15 Mmcfe/d which was sold at the end of third quarter. Management expects 2010 proved reserve percentage growth to be in line with expected full year production growth rates.
In keeping with the Company's strategy of less emphasis on dry gas development and more emphasis on condensate-rich property development, capital spending for 2011 is estimated at $2.3 billion, of which $1.9 billion will be allocated for drilling and completions, $200 million will be allocated for midstream businesses and $200 million will be allocated for potential acquisitions. Of the $1.9 billion budget for drilling and completions, approximately $900 million is planned for the Haynesville Shale, approximately $900 million is budgeted for the Eagle Ford Shale, and approximately $100 million is budgeted for the Fayetteville Shale. Petrohawk's 2011 spending plans contemplate an increase in drilling activity in the Eagle Ford Shale throughout the year and a significant decrease in the Haynesville Shale operated rig count in the second half of the year, down to approximately seven rigs. Production growth for 2011 is estimated to be 30% to 40% year over year before potential divestitures.
During the third quarter, Petrohawk completed its first well in the Haynesville Shale incorporating a revised well design which requires significantly less surface treating pressure during the completion phase than a traditional well. The Mendenhall 10H #1 was completed in early October with a frac cost that was approximately $1 million less than a traditionally drilled well. No problems were encountered during the drilling, completion and production phases of the well, which was put on production at a restricted initial production rate of 8.4 Mmcfe/d. Petrohawk expects to have between 15-20 wells utilizing the new well design drilled, and a portion of those completed, by the end of 2010.
The Company's 2011 capital budget includes running an average of 15 operated rigs in the Eagle Ford Shale, approximately twice the number of rigs operated in 2010. Petrohawk estimates that there are approximately 1,900 net risked condensate-rich locations in both its Hawkville Field and Black Hawk that comprise over 50% of the Company's total acreage position in the Eagle Ford Shale.
"With core positions in both the Haynesville Shale and Eagle Ford Shale, we are weighing current capital expenditures against available liquidity and keeping our focus on strategies geared toward creating long-term value. We believe that our positions in these important plays would be impossible to replicate. We project that Petrohawk will be the first large operator in the Haynesville Shale to meet its leasehold capture goals in mid-2011, and the first to have significant and meaningful flexibility to rebalance the program at that time," said Floyd C. Wilson, Petrohawk's Chairman and Chief Executive Officer. "Despite weak gas prices, our lease-capture drilling activity in the Haynesville Shale is generating significant value by adding low cost proved reserves and setting the stage for decades of low risk development activity. Currently our Eagle Ford Shale production is less than a sixth of the amount we produce in the Haynesville Shale. It is important that we take the necessary steps today to accelerate the condensate-rich opportunities in the Eagle Ford Shale. As we decelerate our activity in the Haynesville Shale in mid 2011, the Eagle Ford is poised to live up to its full potential within our portfolio."
Petrohawk's average production of 685 Mmcfe/d during the quarter included 434 Mmcfe/d in the Haynesville Shale and 67 Mmcfe/d from the Eagle Ford Shale. An additional 95 Mmcfe/d was produced from the Fayetteville Shale, and 89 Mmcfe/d was produced from other areas, including 15 Mmcfe/d from miscellaneous Mid-Continent properties which were divested at the end of the quarter.
During the third quarter, Petrohawk drilled281 gross wells, of which 50 were operated, with a 100% success rate. Of these, 102 were in the Haynesville Shale, 21 in the Eagle Ford Shale, and 149 Fayetteville Shale (primarily non-operated).
Petrohawk began the third quarter with 16 operated rigs running in the play, and is currently running 12 operated rigs, a level it expects to maintain through the end of 2010. Twenty nine operated wells and 73 non-operated wells were drilled during third quarter.
Drilling costs continue to trend down due to increased drilling efficiencies; however, completion costs are trending higher due to inflation in pressure pumping services. The third quarter saw a significant decrease in spud-to spud days, down from 52 days in second quarter to 47 days in third quarter. As further example of this trend, there were 6 wells drilled in less than 40 days, with one of those wells drilled in 30 days spud to spud. A direct result of the increased drilling efficiency is the number of wells drilled. The Company drilled 29 operated wells during the quarter, its highest number of wells ever drilled in one quarter. While this is excellent progress for the long term development of the field and Petrohawk's lease capture program, it has put additional pressure on the 2010 budget.
Petrohawk completed its first well in the Lower Bossier Shale, the Whitney Corp. 19H #1, during the third quarter. The well had an initial production rate on a restricted rate of 7.6 Mmcf/d on a 14/64" choke with 8,300 lbs. of flowing casing pressure. The well is comparable in quality to Haynesville wells that have been produced using restricted rate production practices. Petrohawk will drill a limited number of Lower Bossier Shale wells until the Haynesville Shale lease capture effort is complete, with plans to drill approximately 25% of all wells in the field in the Lower Bossier Shale beginning in 2013.
As mentioned above, Petrohawk's first well incorporating a modified well design, engineered to require lower pressure pumping equipment and decrease overall completion costs, was completed during third quarter. The Mendenhall 10H #1 was successfully completed at a rate of 8.4 Mmcfe/d on a 14/64" choke with 8,320 lbs. flowing casing pressure, with treating pressures that were in line with pre-frac expectations. The Company plans to continue to incorporate and refine this well design with between 15 and 20 similar wells scheduled to be drilled through the remainder of 2010. This reduction in overall hydraulic horsepower requirements needed to fracture stimulate wells drilled using this wellbore design, along with an increase in the number of pressure pumping companies capable of pumping these fracs, could be effective in lowering pressure pumping costs in 2011.
Eagle Ford Shale
Petrohawk operated three rigs in Hawkville Field and five rigs in Black Hawk during the third quarter during which 19 operated wells and 2 non-operated wells were drilled. The total number of Company operated wells drilled in the Eagle Ford Shale to date is 75, with 52 located in Hawkville Field, 21 located in Black Hawk and two located in Red Hawk.
In much the same manner as development in the Haynesville Shale, reservoir optimization methods, related to completion and production practices, are being utilized in the Eagle Ford Shale, and completion results from both Hawkville Field and Black Hawk significantly improved during the quarter. In Hawkville Field, the ten most recent wells completed have averaged 6.2 Mmcf/d and 240 Bc/d (7.6 Mmcfe/d using a 6:1 ratio and 9.0 Mmcfe/d using a 12:1 ratio) on an average choke size of 19/64", a notable reduction in choke size over previous wells. Additionally, initial decline rates appear to be more gradual, not only as a result of restricting production, but also higher performance results from of the recent implementation of hybrid completion technology.
Improved well performance has also been experienced in Black Hawk, where the Company has been producing with slightly larger chokes (15/64") and completing wells with increased proppant volumes and decreased the perforation spacing during completion operations. The average IP rate for the three most recent wells was 3.6 Mcf/d and 1,485 barrels of condensate per day (Bc/d) (13.2 Mmcfe/d using a 6:1 ratio and 22.1 Mmcfe/d using a 12:1 ratio).
Recent results in both of these areas of the Eagle Ford Shale underscore the more precise mapping of a developing core of the Eagle Ford trend. Of over 280,000 net acres controlled by Petrohawk in Hawkville Field and Black Hawk, approximately 60% is in the portion of the gas condensate window that contains approximately 1200 BTU gas, with condensate yields as much as 500 barrels of condensate/Mmcf and an estimated weighted average of approximately 115 barrels of condensate/Mmcf.
2011 Operational Preview
Petrohawk's $1.9 billion drilling and completion budget for 2011 emphasizes a shift in capital spending based on market conditions, opportunities to accelerate certain areas of the Company's Eagle Ford Shale position, and the desire to reduce capital allocated to pure natural gas drilling once the Haynesville Shale lease capture period is effectively completed in mid-year. Capital allocated to the Eagle Ford Shale in 2011 is approximately two and a half times the amount budgeted in 2010. Year-over-year production from the Eagle Ford Shale is expected to increase nearly threefold from approximately 67 Mmcfe/d to approximately 175 Mmcfe/d, of which half is expected to be condensate and natural gas liquids. Capital allocated to the Haynesville Shale is expected to decrease by approximately 35% from 2010 levels, but it should still generate approximately 45% year over year growth. The combined result of the 2011 capital program is expected to generate year-over-year production growth of approximately 30-40%.
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