Petrohawk Energy Corporation
1000 Louisiana, Suite 5600
Houston, Texas 77002
April 24, 2009
Mr. H. Roger Schwall
Assistant Director
U. S. Securities and Exchange Commission
100 F Street, N.E., Mail Stop 7010
Washington, D.C. 20549
| RE: | Petrohawk Energy Corporation (the “Company”) | |
| Form 10-K/A for the Fiscal Year Ended December 31, 2008 | ||
| Filed April 2, 2009 | ||
| Schedule 14A | ||
| Filed March 27, 2009 | ||
| File No. 1-33334 |
Dear Mr. Schwall:
Thank you for the comments included in your letter dated April 17, 2009. I am providing the enclosed responses on behalf of the Company. Each of your comments is reproduced below, with specific responses following each comment.
Form 10-K for Fiscal Year Ended December 31, 2008
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Critical Accounting Policies and Estimates
Full Cost Ceiling Limitation, page 40
| 1. | We note your disclosures that indicate you have sustained a ceiling test write-down using year-end prices. We further note that prices for natural gas have continued to decline subsequent to year end. Please expand this disclosure to present a sensitivity analysis or other indicative information that might be helpful to investors in understanding your exposure to commodity price variations and their impact to your ceiling test. Please also expand your footnote disclosure to address the requirements of paragraphs 13-14 of SOP 94-6. |
Response:
In future annual reports, we will include under the heading “Critical Accounting Policies and Estimates — Full Cost Ceiling Limitation” disclosure showing the effects that a
Mr. H. Roger Schwall
April 24, 2009
Page 2
10% increase or decrease in commodity prices, with all other factors being held constant, would have on our full cost ceiling test limitation. We will also add disclosure to the effect that commodity prices are volatile and changes in prices could have a material impact on our results of operations. We believe that our proposed revised footnote disclosure addresses your comment regarding paragraphs 13-14 of SOP 94-6.
Engineering Comments
Core Operating Regions, page 8
Mid-Continent Regions, page 8
| 2. | We note that you disclose that 49% of your proved reserves in the Elm Grove and Caspiana fields are undeveloped and that you do not plan to drill any wells in these fields in 2009. Please reconcile for us the classification of approximately 336 BCFe as proved undeveloped reserves, representing almost 24% of your total reserves, with the fact that you apparently do not plan to develop those reserves. Also, please tell us when these reserves were first classified as proved undeveloped reserves. |
Response:
We have had an active drilling program in the Elm Grove and Caspiana fields since acquiring the properties via various transactions beginning in 2006. In response to our drilling success in the Haynesville Shale and the adverse effects on capital availability and cost resulting from the current global economic and credit crises, for 2009 we temporarily re-allocated our capital budget to the Haynesville Shale properties to fulfill lease obligations. While we did not allocate capital to the Elm Grove and Caspiana fields for 2009, we expect to resume our drilling program in these areas in 2010 and future years to develop the remainder of the field.
The following table provides the years in which the reserves were first classified as proved undeveloped (PUD) for the Elm Grove and Caspiana fields:
Year | PUD Reserves (in Bcfe) | |
2006 | 167 | |
2007 | 82 | |
2008 | 87 | |
| 336 | ||
| 3. | We note that you disclose that 44% of your proved reserves are undeveloped in the Terryville Field and that you do not plan to drill any wells in this field in 2009. Please reconcile for us the classification of approximately 50 BCFe as proved undeveloped reserves and the fact that you apparently do not plan to develop those reserves. Also, |
Mr. H. Roger Schwall
April 24, 2009
Page 3
please tell us when these reserves were first classified as proved undeveloped reserves. We note that you drilled 49 wells in the Terryville field in 2008 but your total field reserves declined from 122 BCFe in 2007 to 112 BCFe in 2008. |
Response:
We have had an active drilling program in the Terryville field since acquiring the properties in 2006. In response to our drilling success in the Haynesville Shale and the adverse effects on capital availability and cost resulting from the current global economic and credit crises, for 2009 we temporarily re-allocated our capital budget to the Haynesville Shale properties to fulfill lease obligations. While we did not allocate capital to the Terryville field for 2009, we expect to resume our drilling program in this field in 2010 and future years to develop the remainder of the field.
The following table provides the years in which the reserves were first classified as proved undeveloped (PUD) for the Terryville field:
Year | PUD Reserves (in Bcfe) | |
2006 | 14 | |
2007 | 17 | |
2008 | 19 | |
| 50 | ||
In 2008, of the total 49 wells drilled in Terryville, 31 were proved undeveloped locations that did not result in direct reserve additions and the remaining 18 were non-proved well locations. The factors affecting the net change in reserves from 2007 to 2008 in the Terryville field are summarized in the following table:
Terryville Field | Proved Reserves (in Bcfe) | ||
Proved reserves, December 31, 2007 | 122 | ||
Production | (15 | ) | |
Extensions and discoveries | 26 | ||
Performance revisions | (16 | ) | |
Price change revisions | (5 | ) | |
Proved reserves, December 31, 2008 | 112 | ||
The negative performance revision is largely concentrated in one section situated at the southeastern-most edge of the field, where three early-life wells produced below levels forecasted at December 31, 2007. This resulted in reductions to direct reserves corresponding to the three producers as well as six offsetting PUD locations.
Oil and Natural Gas Operations, page 12
| 4. | Please clarify the footnote at the bottom of page 12 regarding why no production history for exploration wells may impact whether they are economic or not upon completion. |
Response:
The referenced clause was not intended to suggest that a lack of production history impacts whether a well is economic or not upon completion. We will not include this clause in future filings.
Risk Factors, page 17
Estimates of proved oil and natural gas reserves are uncertain….., page 21
| 5. | You state that approximately 44% of your proved reserves are undeveloped and |
Mr. H. Roger Schwall
April 24, 2009
Page 4
undeveloped reserves are less certain than estimates of proved developed reserves. The SEC definition of proved reserves found in Rule 4-10(a) of Regulation S-X requires that you be reasonably certain that the reserves you classify as proved will be recovered. This means that the ultimate recovery of reserves is more likely to equal or exceed your estimates than to be less than your estimates. The definition does not contemplate there being less than reasonable certainty in reserve estimates pertaining to properties that are undeveloped. Your risk factor disclosure saying there is less certainty if these conditions prevail, also saying that estimates of oil and gas reserves are uncertain, seem to be contradicting, or mitigating, the criteria of reasonable certainty that is necessary for reserves to be classified as proved. If you are not reasonably certain of recovering all or a portion of your reported reserves, please remove the associated volumes of reserves from your estimates of proved reserves that are disclosed in your filing. If you are reasonably certain that you will recover your reported reserves, please revise your risk factor and any similar disclosure in the document to not imply that proved reserves are not reasonably certain to be recovered. |
Response:
Our disclosure is not intended to suggest that our reported proved reserves are not reasonably certain within SEC requirements but are intended to focus the reader on the fact that they are estimates that are not free from all uncertainty and they are based upon assumptions. In light of your comment, however, we will substitute the word “imprecise” for the word “uncertain” in the heading to the referenced risk factor and delete from the risk factor the sentence “Estimates of proved undeveloped reserves are less certain than estimates of proved developed reserves.” We will include the risk factor, as so revised, in our Form 10-Q for the quarter ended March 31, 2009.
Management’s Discussion and Analysis of Financial Condition and Results of Operations, page 31
| 6. | You disclose that your financial results are largely driven by the volume of your oil and natural gas production and the price you receive for that production. We also note that in earlier disclosure you indicate that in 2008 you drilled 739 wells in your core areas but you only plan to drill about 180 wells in those same areas in 2009. However, we could find no disclosure on how this significantly reduced drilling and development program will affect future results. Please expand your disclosure to provide this information. |
Response:
In 2008 we drilled or participated in a total of 739 wells, comprised of 350 operated and 389 non-operated wells. Our disclosure of 2009 drilling plans was restricted to operated leases. We will expand disclosure in future filings to include the breakout of drilled wells between operated and non-operated.
The reduction from 350 operated wells in 2008 to 180 operated wells in 2009 corresponds to the re-allocation of drilling capital concentrated on the development of the Haynesville Shale. The multi-stage fracture-stimulated horizontal wells
Mr. H. Roger Schwall
April 24, 2009
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targeting the highly pressurized Haynesville Shale are capable of production rates several times the levels experienced by the typical wells that characterized the 2008 drilling program. Therefore, we do not anticipate future production to be adversely impacted by the 2009 drilling program. In fact, on February 25, 2009 we issued a press release (furnished to the SEC on Form 8-K) in which we publicly announced 2009 production targets approximately 40% above 2008 average production levels.
Oil and Natural Gas Reserves, page 87
| 7. | Please tell us how much of your revisions for both oil and gas were due to performance changes and how much were due to price changes. |
Response:
The following table is a break-out of the total reserve revisions for 2008:
Type | Oil (MBbls) | Natural Gas (Mmcf) | Natural Gas Equivalent (Mmcfe) | ||||||
Performance revisions | (808 | ) | (5,014 | ) | (9,862 | ) | |||
Price change revisions | (2,769 | ) | (62,062 | ) | (78,676 | ) | |||
Total reserve revisions | (3,577 | ) | (67,076 | ) | (88,538 | ) | |||
| 8. | You state that in 2007 and 2008 you added 232,065 and 204,787 MCFe respectively from infill drilling in proved fields. Please tell us how many net wells you drilled in each year to book these reserves and if these reserves are all now classified as proved developed reserves. |
Response:
In 2007, we added 232 Bcfe of infill reserves that corresponded to 399 net wells, comprised of 89.5 developed net wells and 309.5 undeveloped net wells. Of the 309.5 net wells that were undeveloped, 57.6 net wells were developed in 2008, leaving 251.9 net wells that remain undeveloped.
In 2008, we added 205 Bcfe of infill reserves that corresponded to 212.1 net wells, which were comprised of 91.4 developed net wells and 120.7 undeveloped net wells.
Of the combined infill reserves of 437 Bcfe, approximately 235 Bcfe, representing 55%, was classified as proved undeveloped at the end of 2008.
| 9. | Please tell us how much oil and gas you forecast to produce in 2008 in the total proved case of your 2007 reserve report. Please reconcile any material differences between your forecasted production and your actual production in 2008. |
Mr. H. Roger Schwall
April 24, 2009
Page 6
Response:
The following tables reconcile the forecasted production with the actual production in 2008:
Forecasted 2008 Production from 2007 Report | Natural Gas (Mmcf) | Oil (MBbls) | Equivalent (Mmcfe) | ||||||
Forecasted production from report | 84,047 | 1,401 | 92,451 | ||||||
Production fromPUD and PDNPcompletions scheduledfor 2008 in report that did not take place (rescheduledbeyond 2008) | (13,933 | ) | (132 | ) | (14,726 | ) | |||
Forecasted production foractual2008 completions | 70,114 | 1,269 | 77,715 | ||||||
Additional productionattributable to2008 acquisitions not included in report | 4,114 | 2 | 4,127 | ||||||
Total adjusted forecasted production 2008 | 74,228 | 1,271 | 81,852 | ||||||
Actual 2008 Production | Natural Gas (Mmcf) | Oil (MBbls) | Equivalent (Mmcfe) | ||||||
Actual production | 102,273 | 1,554 | 111,597 | ||||||
Production from non-proved completions not in report | (22,333 | ) | (158 | ) | (23,281 | ) | |||
Actual production from proved completions | 79,940 | 1,396 | 88,316 | ||||||
The actual production exceeded the forecast production by 6.5 Bcfe, or 8%, due to the combined net effect of better performance and acceleratedexecution of2008well completions.
Schedule 14A filed March 27, 2009
Design of Our Compensation Program, page 20
| 10. | Please provide your targeted goals on which you measure your operating and financial performance for each element of compensation, including the performance factors on which you base your determination for each named executive officers’ annual cash incentives (collectively “targets”), in addition to a description of the specific levels of achievement of each named executive officer relative to the targets. Further, provide any additional information pertaining to each individual’s performance that the compensation committee considered in determining specific payout levels for 2008. See Item 402(b)(1) of Regulation SK. |
If you believe disclosing the targets would result in competitive harm such that the targets
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April 24, 2009
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could be excluded properly under Instruction 4 to Item 402(b) of Regulation SK, please provide on a supplemental basis a detailed explanation supporting your conclusion. If disclosure of quantitative or qualitative performance-related factors would cause competitive harm, you are required to discuss how difficult it will be for you to achieve the target levels or other factors. See Instruction 4 to Item 402(b) of Regulation S-K.
Response:
We have included revised disclosure in our proxy statement on pages 21-24 to address your comment.
Annual Cash Incentives, page 23
| 11. | Explain in more detail the awarding of cash bonuses to senior executives that were two times the targets established for them. Describe the actual targets and clarify what you mean by “taking into account the cash incentives paid….by our compensation peer group.” |
Response:
We have included revised disclosure in our proxy statement on page 24 to address your comment.
**********************
Finally, we acknowledge that:
| • | the company is responsible for the adequacy and accuracy of the disclosure in our filings; |
| • | staff comments or changes to disclosure in response to staff comments do not foreclose the Commission from taking any action with respect to our filings; and |
| • | the company may not assert staff comments as a defense in any proceeding initiated by the Commission or any person under the federal securities laws of the United States. |
We also understand that the Division of Enforcement has access to all information that we provide to the staff of the Division of Corporation Finance in your review of our filings and in response to your comments.
We appreciate your comments and your prompt attention to our responses. If you have any questions or further comments, I can be reached at (832) 204-2772.
Mr. H. Roger Schwall
April 24, 2009
Page 8
| Very truly yours, |
| /s/ David S. Elkouri |
| David S. Elkouri |
| Executive Vice President and |
| General Counsel |
