Petrohawk Energy Corp. (HK, Financial) filed Quarterly Report for the period ended 2010-06-30.
Petrohawk Energy Corp. has a market cap of $4.88 billion; its shares were traded at around $16.15 with a P/E ratio of 35.1 and P/S ratio of 4.5. HK is in the portfolios of David Williams of Columbia Value and Restructuring Fund, John Keeley of Keeley Fund Management, Steven Cohen of SAC Capital Advisors, George Soros of Soros Fund Management LLC, NWQ Managers of NWQ Investment Management Co, Ruane Cunniff of Ruane & Cunniff & Goldfarb Inc, Jeremy Grantham of GMO LLC.
One consequence of continued low natural gas prices is the possibility that we may be required to recognize additional non-cash impairment expense under the full cost method of accounting, which we use to account for our oil and natural gas exploration and development activities. We recorded full cost ceiling impairments before income taxes of approximately $1.8 billion during 2009 ($1.7 billion at March 31 and $106 million at December 31). At June 30, 2010, our net book value of oil and natural gas properties did not exceed the ceiling amount based on the 12-month average Henry Hub price of $4.10 per million British thermal unit (Mmbtu) and West Texas Intermediate (WTI) posted price of $75.61 per Bbl. Changes in prices, production rates, levels of reserves, future development costs, and other factors will determine our ceiling test calculation and impairment analyses in future periods.
We are obligated to deliver minimum annual quantities of natural gas to KinderHawk equal to 50% of our annual projected production from Petrohawk operated wells located on certain dedicated acreage from the Haynesville and Bossier Shales in North Louisiana for the next five years, or in the alternative, pay an annual true-up fee to KinderHawk if such minimum annual quantities are not delivered. We pay KinderHawk negotiated gathering and treating fees, subject to an annual inflation adjustment factor. The gathering fee is equal to $0.34 per Mcf of natural gas delivered at KinderHawks receipt points. The treating fee is charged for gas delivered containing more than 2% by volume of carbon dioxide. For gas delivered containing between 2% and 5.5% carbon dioxide, the treating fee is between $0.030 and $0.345 per Mcf, and for gas containing over 5.5% carbon dioxide, the treating fee starts at $0.365 per Mcf and increases on a scale of $0.09 per Mcf for each additional 1% of carbon dioxide content.
The Senior Credit Agreement provides for a $2.0 billion facility. After taking into account the sale of our interests in the Terryville and WEHLU fields, the borrowing base is $1.3 billion, $1.0 billion of which relates to our oil and natural gas properties and $300 million of which relates to our midstream assets. The Senior Credit Agreement was amended on May 17, 2010 to permit the transactions contemplated by the KinderHawk joint venture. The portion of the borrowing base which relates to our oil and natural gas properties will be redetermined on a semi-annual basis (with the Company and the lenders each having the right to one annual interim unscheduled redetermination) and adjusted based on our oil and natural gas properties, reserves, other indebtedness and other relevant factors. The component of the borrowing base related to our midstream assets is limited to the lesser of $300 million or 3.5 times midstream EBITDA, is automatically determined quarterly and is currently limited to approximately $29 million based on the EBITDA limitation.
Net cash provided by operating activities decreased in 2010 due to the decrease in realized gains on our derivative contracts from $179.2 million for the six months ended June 30, 2009 to $95.4 million for the same period in 2010. This decrease was offset by a 19% increase in our average realized natural gas equivalent price compared to the same period in the prior year as well as a 40% increase in our average daily production volumes due to our drilling successes in the Haynesville, Fayetteville and Eagle Ford Shales. Our natural gas equivalent price increased $0.76 per Mcfe to $4.77 per Mcfe from $4.01 per Mcfe in the prior year. Production for the first six months of 2010 averaged 625 Mmcfe/d compared to 448 Mmcfe/d during the same period of 2009. As a result of our 2010 capital budget program, we expect to continue to increase our production volumes throughout 2010 and 2011. However, we are unable to predict future production levels or future commodity prices with certainty, and, therefore, we cannot provide any assurance about future levels of net cash provided by operating activities.
We reported net income of $13.5 million for the three months ended June 30, 2010 compared to a net loss of $22.0 million for the comparable period in 2009, resulting in a net change of $35.5 million. This change was primarily attributable to the amortization of our deferred gain on the sale of our Haynesville gas gathering system of $64.4 million offset by our loss on derivative contracts of $16.6 million in 2010 compared to a gain of $16.0 million in the prior year.
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Petrohawk Energy Corp. has a market cap of $4.88 billion; its shares were traded at around $16.15 with a P/E ratio of 35.1 and P/S ratio of 4.5. HK is in the portfolios of David Williams of Columbia Value and Restructuring Fund, John Keeley of Keeley Fund Management, Steven Cohen of SAC Capital Advisors, George Soros of Soros Fund Management LLC, NWQ Managers of NWQ Investment Management Co, Ruane Cunniff of Ruane & Cunniff & Goldfarb Inc, Jeremy Grantham of GMO LLC.
Highlight of Business Operations:
Our 2010 capital budget is focused on the development of non-proved reserve locations in our Haynesville, Bossier, Eagle Ford and Fayetteville Shale plays so that we can hold our acreage in these areas. We also believe these projects offer us the potential for high internal rates of return and reserve growth. Our original 2010 capital budget included spending of approximately $1.45 billion on drilling and completions, of which $900 million was allocated to our Haynesville and Bossier Shale properties, $350 million to our Eagle Ford Shale properties, $100 million to our Fayetteville Shale properties and $100 million to our remaining properties. On April 13, 2010, we announced a reallocation and $100 million reduction to our planned 2010 capital spending for drilling and completions. Our current 2010 capital budget includes spending for drilling and completions of approximately $1.35 billion and includes $850 million allocated to our Haynesville and Bossier Shale properties, $390 million to our Eagle Ford Shale properties, $85 million to our Fayetteville Shale properties and $25 million to our remaining properties. Recently, our costs for certain well completion services have begun to increase significantly, primarily in response to strong demand among oil and natural gas companies operating in the Eagle Ford and Haynesville Shale plays. We are actively engaged in efforts to control or offset these costs. However, if we are unable to control or offset these costs, we estimate that actual 2010 capital expenditures may exceed our current budget. We continually monitor our capital expenditures program and may alter our capital expenditures budget and future drilling plans in response to these and various other factors, some of which are beyond our control, including drilling results, oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints and regulatory approvals. To the extent these factors lead to reductions in our drilling plans or increases in our associated capital budgets in future periods, our financial position, cash flows and operating results could be adversely impacted.One consequence of continued low natural gas prices is the possibility that we may be required to recognize additional non-cash impairment expense under the full cost method of accounting, which we use to account for our oil and natural gas exploration and development activities. We recorded full cost ceiling impairments before income taxes of approximately $1.8 billion during 2009 ($1.7 billion at March 31 and $106 million at December 31). At June 30, 2010, our net book value of oil and natural gas properties did not exceed the ceiling amount based on the 12-month average Henry Hub price of $4.10 per million British thermal unit (Mmbtu) and West Texas Intermediate (WTI) posted price of $75.61 per Bbl. Changes in prices, production rates, levels of reserves, future development costs, and other factors will determine our ceiling test calculation and impairment analyses in future periods.
We are obligated to deliver minimum annual quantities of natural gas to KinderHawk equal to 50% of our annual projected production from Petrohawk operated wells located on certain dedicated acreage from the Haynesville and Bossier Shales in North Louisiana for the next five years, or in the alternative, pay an annual true-up fee to KinderHawk if such minimum annual quantities are not delivered. We pay KinderHawk negotiated gathering and treating fees, subject to an annual inflation adjustment factor. The gathering fee is equal to $0.34 per Mcf of natural gas delivered at KinderHawks receipt points. The treating fee is charged for gas delivered containing more than 2% by volume of carbon dioxide. For gas delivered containing between 2% and 5.5% carbon dioxide, the treating fee is between $0.030 and $0.345 per Mcf, and for gas containing over 5.5% carbon dioxide, the treating fee starts at $0.365 per Mcf and increases on a scale of $0.09 per Mcf for each additional 1% of carbon dioxide content.
The Senior Credit Agreement provides for a $2.0 billion facility. After taking into account the sale of our interests in the Terryville and WEHLU fields, the borrowing base is $1.3 billion, $1.0 billion of which relates to our oil and natural gas properties and $300 million of which relates to our midstream assets. The Senior Credit Agreement was amended on May 17, 2010 to permit the transactions contemplated by the KinderHawk joint venture. The portion of the borrowing base which relates to our oil and natural gas properties will be redetermined on a semi-annual basis (with the Company and the lenders each having the right to one annual interim unscheduled redetermination) and adjusted based on our oil and natural gas properties, reserves, other indebtedness and other relevant factors. The component of the borrowing base related to our midstream assets is limited to the lesser of $300 million or 3.5 times midstream EBITDA, is automatically determined quarterly and is currently limited to approximately $29 million based on the EBITDA limitation.
Net cash provided by operating activities decreased in 2010 due to the decrease in realized gains on our derivative contracts from $179.2 million for the six months ended June 30, 2009 to $95.4 million for the same period in 2010. This decrease was offset by a 19% increase in our average realized natural gas equivalent price compared to the same period in the prior year as well as a 40% increase in our average daily production volumes due to our drilling successes in the Haynesville, Fayetteville and Eagle Ford Shales. Our natural gas equivalent price increased $0.76 per Mcfe to $4.77 per Mcfe from $4.01 per Mcfe in the prior year. Production for the first six months of 2010 averaged 625 Mmcfe/d compared to 448 Mmcfe/d during the same period of 2009. As a result of our 2010 capital budget program, we expect to continue to increase our production volumes throughout 2010 and 2011. However, we are unable to predict future production levels or future commodity prices with certainty, and, therefore, we cannot provide any assurance about future levels of net cash provided by operating activities.
We reported net income of $13.5 million for the three months ended June 30, 2010 compared to a net loss of $22.0 million for the comparable period in 2009, resulting in a net change of $35.5 million. This change was primarily attributable to the amortization of our deferred gain on the sale of our Haynesville gas gathering system of $64.4 million offset by our loss on derivative contracts of $16.6 million in 2010 compared to a gain of $16.0 million in the prior year.
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