Exhibit 99.1
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November 2012 |
To: Australian Securities Exchange cc: New York Stock Exchange London Stock Exchange JSE Limited
PETROHAWK SEPTEMBER 2012 FINANCIAL REPORT
Petrohawk Energy Corporation (Petrohawk) provides periodic reports to holders of Petrohawk’s senior notes as required in accordance with the reporting covenants under the applicable indentures. A copy of Petrohawk’s September 2012 financial report is attached, and will be provided to the holders of Petrohawk’s outstanding senior notes today.
Petrohawk’s financial statements are prepared in accordance with United States accounting standards whereas BHP Billiton Group financial statements are prepared in accordance with International Financial Reporting Standards and include the impact of the purchase price paid for Petrohawk. In addition, the unaudited condensed consolidated financial statements contained in the quarterly financial report are based on Petrohawk’s historical accounting activities and do not reflect the acquisition of Petrohawk by BHP Billiton or any of the fair value calculations that were performed in conjunction with the business combination accounting performed by BHP Billiton. For the avoidance of doubt, the results of operations, financial position, cash flows and disclosures included in the Petrohawk Quarterly Report are not indicative of the contribution of Petrohawk to the potential results of BHP Billiton.
BHP Billiton purchased Petrohawk on 20 August 2011 and therefore only consolidates Petrohawk’s results in its financial statements from that date.
Further information on BHP Billiton can be found at: www.bhpbilliton.com
Jane McAloon
Group Company Secretary
BHP Billiton Limited ABN 49 004 028 077 BHP Billiton Plc Registration number 3196209
Registered in Australia Registered in England and Wales
Registered Office: 180 Lonsdale Street Melbourne Victoria 3000 Registered Office: Neathouse Place, London SW1V 1BH United Kingdom
The BHP Billiton Group is headquartered in Australia
PETROHAWK ENERGY CORPORATION QUARTERLY REPORT TO SECURITY HOLDERS
SEPTEMBER 30, 2012
The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States. Petrohawk Energy Corporation’s (Petrohawk or the Company) parent, BHP Billiton Limited, prepares its consolidated financial statements in accordance with International Financial Reporting Standards (IFRS). The Company utilizes the full cost method of accounting for its oil and natural gas activities compared to BHP Billiton Limited which utilizes the successful efforts method of accounting. In addition, the accompanying unaudited condensed consolidated financial statements are based on the Company’s historical accounting activities and do not reflect the acquisition of the Company by BHP Billiton Limited or any of the fair value calculations that were performed in conjunction with the business combination accounting performed by BHP Billiton Limited. For the avoidance of doubt, the results of operations, financial position, cash flows and disclosures included in this document are not indicative of the potential contribution to the results of BHP Billiton Limited.
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PETROHAWK ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited) (In thousands)
Three Months Ended September Nine Months Ended September 2012 2011 2012 2011 Operating revenues:
Oil and natural gas $ 502,475 $ 491,288 $ 1,467,749 $ 1,285,225 Marketing 5,329 5,916 5,262 295,946 Midstream 17,804 5,019 58,582 12,167 Total operating revenues 525,608 502,223 1,531,593 1,593,338
Operating expenses:
Marketing 4,976 6,319 4,976 322,266 Production: Lease operating 22,777 17,333 67,068 43,670 Workover and other 4,409 2,863 12,652 12,047 Taxes other than income 17,191 18,563 47,071 48,142 Gathering, transportation and other 75,995 56,223 233,745 99,736 General and administrative 35,500 132,982 134,745 224,463 Depletion, depreciation and amortization 312,228 231,726 890,292 590,507 Impairment of capitalized software costs — — 1,351 — Total operating expenses 473,076 466,009 1,391,900 1,340,831
Income from operations 52,532 36,214 139,693 252,507
Other income (expenses):
Net gain (loss) on derivative contracts — 199,440 (28,260) 232,040 Interest expense and other (107,530) (108,658) (322,943) (283,297) Total other income (expenses) (107,530) 90,782 (351,203) (51,257) (Loss) income from continuing operations before income taxes (54,998) 126,996 (211,510) 201,250 Income tax benefit (provision) 22,332 (45,350) 77,070 (73,571) (Loss) income from continuing operations, net of income taxes (32,666) 81,646 (134,440) 127,679 Loss from discontinued operations, net of income taxes — (42) — (3,201) Net (loss) income $ (32,666) $ 81,604 $ (134,440) $ 124,478
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.
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PETROHAWK ENERGY CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (In thousands, except share and per share amounts)
September 30, December 31, 2012 2011 Current assets:
Cash $ 193,873 $ 174,436 Accounts receivable 592,304 410,115 Receivables from derivative contracts — 371,584 Deferred income taxes 15,588 -Prepaids and other 30,714 42,060 Total current assets 832,479 998,195
Oil and natural gas properties (full cost method):
Evaluated 12,513,006 10,509,954 Unevaluated 2,698,144 2,502,435 Gross oil and natural gas properties 15,211,150 13,012,389 Less—accumulated depletion (6,443,494) (5,598,420) Net oil and natural gas properties 8,767,656 7,413,969
Other operating property and equipment:
Gas gathering systems and equipment 1,260,581 918,810 Other operating assets 129,176 108,077 Gross other operating property and equipment 1,389,757 1,026,887 Less—accumulated depreciation (105,993) (61,363) Net other operating property and equipment 1,283,764 965,524
Other noncurrent assets:
Goodwill 932,802 932,802 Other intangible assets, net of amortization 70,000 78,289 Debt issuance costs, net of amortization 38,404 45,528 Deferred income taxes 331,144 326,878 Receivables from derivative contracts — 5,147 Restricted cash 32,842 34,736 Other 19,673 11,859
Total assets $ 12,308,764 $ 10,812,927
Current liabilities:
Accounts payable and accrued liabilities $ 1,278,759 $ 963,701 Deferred income taxes — 79,748 Liabilities from derivative contracts — 40,673 Payable on financing arrangement 19,246 17,631 Long-term debt — 17,520 Total current liabilities 1,298,005 1,119,273
Long-term debt 3,199,390 3,192,641
Other noncurrent liabilities:
Asset retirement obligations 48,499 52,317 Payable on financing arrangement 1,834,848 1,799,881 Other 1,800 640 Commitments and contingencies
Stockholders’ equity:
Common stock: 100 shares of $.001 par value authorized, issued and outstanding at September 30, 2012 and December 31, 201 — -Additional paid-in capital 7,072,886 5,660,399 Accumulated deficit (1,146,664) (1,012,224) Total stockholders’ equity 5,926,222 4,648,175
Total liabilities and stockholders’ equity $ 12,308,764 $ 10,812,927
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements. 4
PETROHAWK ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) (In thousands)
Nine Months Ended September 30, 2012 2011 Cash flows from operating activities:
Net (loss) income $ (134,440) $ 124,478 Adjustments to reconcile net (loss) income to net cash provided by operating activities: Depletion, depreciation and amortization 890,292 589,160 Impairment of capitalized software costs 1,351 -Income tax (benefit) provision (77,070) 71,593 Loss on sale — 3,950 Stock-based compensation — 53,203 Net unrealized gain on derivative contracts 336,058 (50,580) Other operating 34,660 29,140 Change in assets and liabilities: Accounts receivable (182,189) (51,272) Prepaids and other 11,035 13,295 Accounts payable and accrued liabilities 169,665 (12,409) Payable to KinderHawk Field Services LLC — (976) Other (6,063) (3,879) Net cash provided by operating activities 1,043,299 765,703
Cash flows from investing activities:
Oil and natural gas capital expenditures (2,110,037) (2,353,101) Proceeds received from sale of oil and natural gas properties — 86,438 Proceeds received from sale of Fayetteville gas gathering systems — 76,898 Marketable securities purchased — (896,006) Marketable securities redeemed — 896,006 Increase in restricted cash (80,281) (295,748) Decrease in restricted cash 82,175 295,748 Other operating property and equipment capital expenditures (330,898) (236,570) Net cash used in investing activities (2,439,041) (2,426,335)
Cash flows from financing activities:
Proceeds from exercise of stock options — 5,426 Contribution from parent 1,407,455 628,375 Restricted stock awards settled — (85,904) Stock option awards and stock option appreciation rights settled — (224,216) Proceeds from borrowings — 4,386,500 Repayment of borrowings (17,520) (3,752,157) Increase in payable on financing arrangement 49,779 836,355 Decrease in payable on financing arrangement (24,535) (4,008) Debt issuance costs — (25,982) Other — (4,423) Net cash provided by financing activities 1,415,179 1,759,966
Net increase in cash 19,437 99,334 Cash at beginning of period 174,436 1,591 Cash at end of period $ 193,873 $ 100,925
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.
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PETROHAWK ENERGY CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)
1. FINANCIAL STATEMENT PRESENTATION
Petrohawk Energy Corporation (Petrohawk or the Company) is engaged in the exploration, development and production of predominately natural gas properties located in the United States. As further discussed under the heading “Merger” below, on August 25, 2011, BHP Billiton Limited, a corporation organized under the laws of Victoria, Australia (BHP Billiton Limited), acquired 100% of the outstanding shares of the Company, with Petrohawk continuing as the surviving entity. Petrohawk remains an indirect, wholly owned subsidiary of BHP Billiton Limited. The unaudited condensed consolidated financial statements include the accounts of all majority-owned, controlled subsidiaries of the Company. All intercompany accounts and transactions have been eliminated. Certain prior year amounts have been reclassified to conform to the current year presentation. These unaudited condensed consolidated financial statements reflect, in the opinion of the Company’s management, all adjustments, consisting only of normal and recurring adjustments, necessary to present fairly the financial position as of, and the results of operations for, the periods presented. During interim periods, Petrohawk follows the accounting policies disclosed in its 2011 Annual Report on Form 10-K filed with the United States Securities and Exchange Commission. Please refer to the footnotes in the 2011 Annual Report on Form 10-K when reviewing interim financial results.
Merger
On July 14, 2011, the Company entered into an agreement and plan of merger (Merger Agreement) with BHP Billiton Limited (Guarantor), BHP Billiton Petroleum (North America) Inc. (Parent), a Delaware corporation and a wholly owned subsidiary of Guarantor, and North America Holdings II Inc., a Delaware corporation (Purchaser) and a wholly owned subsidiary of Parent. Pursuant to the Merger Agreement, on August 20, 2011, Purchaser accepted for payment all of the outstanding shares of the Company’s common stock, par value $0.001 per share, validly tendered and not validly withdrawn pursuant to the tender offer for $38.75 per share (Offer Price), net to the seller in cash. Additionally, and pursuant to the Merger Agreement, on August 25, 2011, Purchaser merged with and into the Company, with Petrohawk continuing as the surviving corporation in the merger and as a wholly owned subsidiary of Parent (the BHP Merger).
Use of Estimates
The preparation of the Company’s unaudited condensed consolidated financial statements in conformity with accounting principles generally accepted in the United States requires the Company’s management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the unaudited condensed consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods. The Company bases its estimates and judgments on historical experience and on various other assumptions and information that are believed to be reasonable under the circumstances. Estimates and assumptions about future events and their effects cannot be perceived with certainty and, accordingly, these estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as the Company’s operating environment changes. Actual results may differ from the estimates and assumptions used in the preparation of the Company’s unaudited condensed consolidated financial statements.
Interim period results are not necessarily indicative of results of operations or cash flows for the full year and accordingly, certain information normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States has been condensed or omitted. The Company has evaluated events or transactions through the date of issuance of these unaudited condensed consolidated financial statements.
Gas Gathering Systems and Equipment and Other Operating Assets
Gas gathering systems and equipment are recorded at cost. Depreciation is calculated using the straight-line method over a 30-year estimated useful life. Upon disposition, the cost and accumulated depreciation are removed and any gains or losses are reflected in current operations. Maintenance and repair costs are charged to operating expense as incurred. Material expenditures which increase the life of an asset are capitalized and depreciated over the estimated remaining useful life of the asset. The Company did not capitalize any interest related to the construction of the Company’s gas gathering systems and
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equipment for the three and nine months ended September 30, 2012 and capitalized $0.1 million and $1.8 million of interest for the three and nine months ended September 30, 2011.
The contribution of the Company’s Haynesville Shale gas gathering and treating business to KinderHawk Field Services LLC (KinderHawk) on May 21, 2010 for a 50% membership interest and approximately $917 million in cash is accounted for in accordance with Financial Accounting Standards Board’s (FASB) Accounting Standards Codification (ASC) Subtopic 360-20, Property, Plant and Equipment–Real Estate Sales (ASC 360-20). Under the financing method, the historical cost of the Haynesville Shale gas gathering system contributed to KinderHawk is carried at the full historical basis of the assets on the unaudited condensed consolidated balance sheets in “Gas gathering systems and equipment” and depreciated over the remaining useful life of the assets. Contributions to KinderHawk from the Company and the joint venture partner are recorded as increases in “Gas gathering systems and equipment” on the unaudited condensed consolidated balance sheets. On July 1, 2011, the Company transferred its remaining 50% membership interest in KinderHawk to KM Gathering LLC (KM Gathering).
On July 1, 2011, the Company transferred a 25% interest in EagleHawk Field Services LLC (EagleHawk) to KM Eagle Gathering LLC (Eagle Gathering). The EagleHawk transaction is accounted for in accordance with ASC 360-20. Under the financing method, the historical cost of the Eagle Ford Shale gas gathering systems contributed to EagleHawk is carried at the full historical basis of the assets on the unaudited condensed consolidated balance sheets in “Gas gathering systems and equipment” and depreciated over the remaining useful life of the assets. Contributions to EagleHawk from the Company and the joint venture partner are recorded as increases in “Gas gathering systems and equipment” on the unaudited condensed consolidated balance sheets.
See Note 2, “Acquisitions and Divestitures” for more details regarding the KinderHawk and EagleHawk joint venture arrangements and for discussion of the accounting treatment related to the arrangements.
Gas gathering systems and equipment as of September 30, 2012 and December 31, 2011 consisted of the following:
September 30, December 31,
2012 (1)(2) 2011 (1)(2)
(In thousands)
Gas gathering systems and equipment $ 1,260,581 $ 918,810 Less — accumulated depreciation (56,803) (33,162) Net gas gathering systems and equipment $ 1,203,778 $ 885,648
(1) Under the financing method, the historical cost of the Haynesville Shale gas gathering system contributed to KinderHawk is carried at the full historical basis of the assets on the unaudited condensed consolidated balance sheets in “Gas gathering systems and equipment” and depreciated over the remaining useful life of the assets. As of September 30, 2012 and December 31, 2011, the table above includes approximately $409.0 million and $420.0 million, respectively, attributed to the net carrying value of the assets contributed to KinderHawk.
(2) Under the financing method, the historical cost of the Eagle Ford Shale gas gathering systems contributed to EagleHawk is carried at the full historical basis of the assets on the unaudited condensed consolidated balance sheets in “Gas gathering systems and equipment” and depreciated over the remaining useful life of the assets. As of September 30, 2012 and December 31, 2011, the table above includes approximately $665.5 million and $437.3 million, respectively, attributed to the net carrying value of the assets contributed to EagleHawk.
Other operating property and equipment are recorded at cost. Depreciation is calculated using the straight-line method over the following estimated useful lives: automobiles, leasehold improvements, furniture and equipment, five years or the lesser of lease term; rental equipment, seven years; computers, three years and capitalized software implementation costs, eighteen months. Upon disposition, the cost and accumulated depreciation are removed and any gains or losses are reflected in current operations. Maintenance and repair costs are charged to operating expense as incurred. Material expenditures which increase the life of an asset are capitalized and depreciated over the estimated remaining useful life of the asset.
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The Company reviews its gas gathering systems and equipment and other operating assets in accordance with ASC 360, Property, Plant, and Equipment (ASC 360). ASC 360 requires the Company to evaluate gas gathering systems and equipment and other operating assets as events occur or circumstances change that would more likely than not reduce the fair value below the carrying amount. If the carrying amount is not recoverable from its undiscounted cash flows, then the Company would recognize an impairment loss for the difference between the carrying amount and the current fair value. Further, the Company evaluates the remaining useful lives of its gas gathering systems and equipment and other operating assets at each reporting period to determine whether events and circumstances warrant a revision to the remaining depreciation periods. During the first quarter of 2012, the Company made the decision to cease implementation of a new budgeting software program. As such, the Company impaired the capitalized costs associated with this software implementation in the first quarter of 2012. Approximately $1.3 million was recorded to “Impairment of capitalized software costs” in the unaudited condensed consolidated statements of operations during the period the impairment was recognized.
Payable on Financing Arrangement
The contribution of the Company’s Haynesville Shale gas gathering and treating business to KinderHawk on May 21, 2010 for a 50% membership interest and approximately $917 million in cash is accounted for in accordance with ASC 360-20. Due to the gathering agreement entered into with the formation of KinderHawk, which constitutes extended continuing involvement under ASC 360-20, it has been determined that the contribution of the Company’s Haynesville Shale gathering and treating system to form KinderHawk is accounted for as a failed sale of in substance real estate. See Note 2, “Acquisitions and Divestitures” for more details regarding the KinderHawk joint venture arrangement and for discussion of the accounting treatment related to the arrangement. Under the financing method for a failed sale of in substance real estate, on May 21, 2010, the Company recorded a financing obligation on the unaudited condensed consolidated balance sheets in “Payable on financing arrangement,” in the amount of approximately $917 million. Reductions to the obligation and the non cash interest on the financing obligation are tied to the gathering and treating services, as the Company delivers natural gas through the Haynesville Shale gathering and treating system. Interest and principal are determined based upon the allocable income to the joint venture partner, and interest is limited up to an amount that is calculated based upon the Company’s weighted average cost of debt as of the date of the transaction. Allocable income in excess of the calculated value is reflected as reductions of principal. Interest is recorded in “Interest expense and other” on the unaudited condensed consolidated statements of operations. On July 1, 2011, the Company transferred its remaining 50% membership interest in KinderHawk to KM Gathering. See further discussion in Note 2, “Acquisitions and Divestitures.” As a result of the transfer on July 1, 2011, the Company recorded an increase in its financing obligation associated with KinderHawk of approximately $743.0 million.
The Company’s transfer of a 25% interest in EagleHawk on July 1, 2011 to Eagle Gathering is accounted for in accordance with ASC 360-20. Due to the gathering agreements which constitute extended continuing involvement under ASC 360-20, it has been determined that the transfer of the Company’s Eagle Ford Shale gathering and treating systems to EagleHawk is accounted for as a failed sale of in substance real estate. See Note 2, “Acquisitions and Divestitures” for more details regarding the EagleHawk joint venture arrangement and for discussion of the accounting treatment related to the arrangement. Under the financing method for a failed sale of in substance real estate, on July 1, 2011, the Company recorded a financing obligation on the unaudited condensed consolidated balance sheets in “Payable on financing arrangement,” in the amount of approximately $93 million. Reductions to the obligation and the non cash interest on the financing obligation are tied to the gathering and treating services, as the Company delivers natural gas through the Eagle Ford Shale gathering and treating systems. Interest and principal are determined based upon the allocable income to the joint venture partner, and interest is limited up to an amount that is calculated based upon the Company’s weighted average cost of debt as of the date of the transaction. Allocable income in excess of the calculated value is reflected as reductions of principal.
The balance of the Company’s financing obligations as of September 30, 2012 and December 31, 2011, was approximately $1.9 billion, of which approximately $19.2 million and $17.6 million was classified as current for the respective periods.
Marketing Revenue and Expense
Historically, for production from certain operating areas, a subsidiary of the Company purchased and sold the Company’s own and third party natural gas produced from wells which the Company and third parties operated. The revenues and expenses related to these marketing activities were reported on a gross basis as part of operating revenues and operating expenses in historical periods. Marketing revenues were recorded at the time natural gas was physically delivered to third parties at a fixed or index price. Marketing expenses attributable to gas purchases were recorded as the subsidiary of the Company took physical title to natural gas and transported the purchased volumes to the point of sale. Effective July 1, 2011, the Company’s marketing subsidiary ceased its marketing operations. Therefore, the Company no longer reflects these 8
activities on a gross basis on the unaudited condensed consolidated statements of operations. As a result, certain items previously recorded to “Marketing revenues” are no longer reported while others are now recorded to “Oil and natural gas revenues” on the unaudited condensed consolidated statements of operations. In addition, certain charges previously reported in “Marketing expenses” are no longer recorded while others are now recorded to “Gathering, transportation and other” on the unaudited condensed consolidated statements of operations. During the third quarter of 2012, the Company purchased and sold natural gas from a third party and may look to do so again in the future.
Midstream Revenues
Revenues from the Company’s midstream operations are derived from providing gathering and treating services for the Company and other owners in wells which the Company and third parties operate. Revenues are recognized when services are provided at a fixed or determinable price, collectability is reasonably assured and evidenced by a contract. The Company’s midstream operations do not take title to the natural gas for which services are provided, with the exception of imbalances that are monthly cash settled. The imbalances are recorded using published natural gas market prices.
The contribution of the Company’s Haynesville Shale gas gathering and treating business to KinderHawk on May 21, 2010 for a 50% membership interest and approximately $917 million in cash is accounted for in accordance with ASC 360-20. Under the financing method for a failed sale of in substance real estate, the Company recorded KinderHawk’s revenues, net of eliminations for intercompany amounts associated with gathering and treating services provided to the Company, on the unaudited condensed consolidated statements of operations in “Midstream revenues.” On July 1, 2011, following the transfer of the Company’s remaining 50% membership interest in KinderHawk to KM Gathering, KinderHawk’s revenues are no longer recorded in the Company’s unaudited condensed consolidated statements of operations in “Midstream revenues.”
The Company’s transfer of a 25% interest in EagleHawk on July 1, 2011, to Eagle Gathering is accounted for in accordance with ASC 360-20. Under the financing method for a failed sale of in substance real estate, the Company records EagleHawk’s revenues, net of eliminations for intercompany amounts associated with gathering and treating services provided to the Company, on the unaudited condensed consolidated statements of operations in “Midstream revenues.”
See Note 2, “Acquisitions and Divestitures” for more details regarding the KinderHawk and EagleHawk joint venture arrangements and for discussion of the accounting treatment related to the arrangements.
Goodwill
Goodwill represents the excess of the purchase price over the estimated fair value of the identifiable assets acquired net of the fair value of liabilities assumed in an acquisition. ASC 350, Intangibles—Goodwill and Other (ASC 350) requires that intangible assets with indefinite lives, including goodwill, be evaluated on an annual basis for impairment or more frequently if events occur or circumstances change that could potentially result in impairment. The Company performs its goodwill test annually during the third quarter or more often if circumstances require. In accordance with ASU No. 2011-08, Testing for Goodwill Impairment, (ASU 2011-08), the Company completed its annual goodwill impairment test during the third quarter of 2012 and based on this review, no goodwill impairment was deemed necessary.
Other Intangible Assets
The Company treats the costs associated with acquired transportation contracts as other intangible assets which will be amortized over the life of the extended agreement. The initial amount recorded represents the fair value of the contract at the time of acquisition, which is amortized using the straight-line method over the life of the contract. Any unamortized balance of the Company’s other intangible assets is subject to impairment testing pursuant to the Impairment or Disposal of Long-Lived Assets Subsections of ASC Subtopic 360-10 (ASC 360-10). The Company reviews its intangible assets for potential impairment whenever events or changes in circumstances indicate that an other-than-temporary decline in the value of the investment has occurred.
Effective July 1, 2011 and in conjunction with the elimination of the Company’s marketing activities, amortization expense of $2.8 million and $8.3 million for the three and nine months ended September 30, 2012, respectively, is included in “Gathering, transportation and other” on the unaudited condensed consolidated statements of operations. Amortization expense was $2.8 million and $8.3 million for the three and nine months ended September 30, 2011, and was allocated to operating expenses between “Marketing” and “Gathering, transportation and other” based on the usage of the contract. The estimated amortization expense will be approximately $11.1 million per year for the remainder of the contract through 2019.
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Other intangible assets subject to amortization at September 30, 2012 and December 31, 2011 are as follows:
September 30, December 31, 2012 2011 (In thousands)
Transportation contracts $ 105,108 $ 105,108 Less — accumulated amortization (35,108) (26,819) Net transportation contracts $ 70,000 $ 78,289
Discontinued Operations
Certain amounts related to the Company’s Fayetteville Shale midstream operations and other operating property and equipment have been reclassified to discontinued operations for all periods presented. Unless otherwise noted, information contained in the notes to the unaudited condensed consolidated financial statements relates to the Company’s continuing operations. See Note 11, “Discontinued Operations,” for further discussion of the presentation of the Company’s Fayetteville Shale midstream and other operating assets as discontinued operations.
Recently Issued Accounting Pronouncements
In July 2011, the FASB issued Accounting Standards Update (ASU) No. 2011-06, Fees Paid to the Federal Government by Health Insurers (ASU 2011-06). This amendment discusses how health insurers should recognize and classify in their income statements the fees mandated by the Health Care and Education Reconciliation Act (the Acts). The Acts impose an annual fee upon health insurers for each calendar year on or after January 1, 2014. The annual fee imposed on the health insurance industry will be allocated to individual entities providing health insurance to employees based on a ratio, as provided for in the Acts. The health insurer’s portion of the fee becomes payable to the United States Treasury once an entity provides health insurance for any United States health risk for each calendar year. ASU 2011-06 specifies that the liability for the entity’s fee should be estimated and recorded in full once the entity has provided qualifying health insurance in the calendar year in which the fee is payable to the government. A corresponding deferred cost should be recorded and amortized on a straight line basis (unless a better amortization method is available) over the calendar year that the fee is payable. The amendments in this update are effective for calendar years beginning after December 15, 2013, once the fee is instituted. The Company is currently assessing the impact that the adoption of ASU 2011-06 will have on its operating results, financial position, cash flows and disclosures.
In September 2011, the FASB issued ASU 2011-08 to simplify how companies test goodwill for impairment. ASU 2011-08 simplifies testing for goodwill impairments by allowing entities to first assess qualitative factors to determine whether the facts or circumstances lead to the conclusion that it is more likely than not that the fair value of a reporting unit is less than the carrying amount. If the entity concludes that it is not more likely than not that the fair value of a reporting unit is less than its carrying amount, then the entity does not have to perform the two-step impairment test. However, if that same conclusion is not reached, the company is required to perform the first step of the two-step impairment test. In this step, the fair value of the reporting unit is calculated and compared to the carrying amount of the reporting unit. If the carrying amount exceeds the fair value, then the entity must perform the second step of the impairment test to measure the amount of the impairment loss, if any. ASU 2011-08 allows a company to bypass the qualitative assessment and proceed directly with performing the two-step goodwill impairment test. ASU 2011-08 is effective for annual and interim goodwill impairment tests for fiscal years beginning after December 15, 2011 and early adoption is permitted. The Company adopted the provisions of ASU 2011-08 in its goodwill impairment test conducted in the third quarter of 2011.
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2. ACQUISITIONS AND DIVESTITURES
Acquisitions
CEU Hawkville, LLC
On December 22, 2011, the Company completed the acquisition of CEU Hawkville, LLC (CEU Hawkville Acquisition), in which it purchased all of the outstanding membership interests in CEU Hawkville for $90 million, before customary closing adjustments. CEU Hawkville’s assets consist primarily of interests in oil and natural gas properties in the Hawkville Field of the Eagle Ford Shale. The transaction had an effective date of October 1, 2011. Upon closing of the transaction, the Company changed the name of CEU Hawkville, LLC to South Texas Shale LLC.
The CEU Hawkville Acquisition was accounted for using the purchase method of accounting under ASC 805, Business Combinations (ASC 805). The Company reflected the results of operations of CEU Hawkville beginning December 22, 2011. The Company recorded the estimated fair values of the assets acquired and liabilities assumed at December 22, 2011, which primarily consisted of oil and natural gas properties of $90.1 million and asset retirement obligations of $0.3 million. As a result, the assets and liabilities of CEU Hawkville were included in the Company’s December 31, 2011 consolidated balance sheet. The purchase price allocation is preliminary and subject to change as additional information becomes available. The Company does not expect to make any material changes to the original purchase price allocation.
Divestitures
Midstream Transactions
On July 1, 2011, the Company closed previously announced transactions with KM Gathering and Eagle Gathering, each of which is an affiliate of Kinder Morgan Energy Partners, L.P., a publicly traded master limited partnership (Kinder Morgan), in which Hawk Field Services LLC (Hawk Field Services) transferred (i) its remaining 50% membership interest in KinderHawk to KM Gathering and (ii) a 25% interest in EagleHawk to Eagle Gathering, in exchange for aggregate cash consideration of approximately $836 million. In conjunction with the closing of the transactions, the balance of the Company’s capital commitment to KinderHawk, approximately $41.4 million as of July 1, 2011, was relieved. The Company’s commitment to deliver certain minimum annual quantities of natural gas through the Haynesville gathering system through May 2015 was not relieved in the transfer. The effective date of the transactions is July 1, 2011. See “Hawk Field Services, LLC Joint Venture” below for more details regarding the initial joint venture arrangement between Hawk Field Services and Kinder Morgan and for discussion of the accounting treatment for both KinderHawk transactions.
EagleHawk engages in the natural gas midstream business in the Eagle Ford Shale in South Texas. EagleHawk holds the Company’s gathering and treating assets and business serving the Company’s Hawkville and Black Hawk Fields in the Eagle Ford Shale. EagleHawk has agreements with the Company covering gathering and treating of natural gas and transportation of condensate and pursuant to which the Company dedicates its production from its Eagle Ford Shale leases. Hawk Field Services manages EagleHawk’s operations.
The EagleHawk joint venture is accounted for as a failed sale of in substance real estate under the provisions of ASC 360-20. ASC 360-20 establishes standards for recognition of profit on all real estate sales transactions other than retail land sales, without regard to the nature of the seller’s business. In making the determination of whether a transaction qualifies, in substance, as a sale of real estate, the nature of the entire real estate being sold is considered, including the land plus the property improvements and the integral equipment. The Eagle Ford Shale gathering and treating systems, consist of right of ways, pipelines and processing facilities. Due to the gathering agreements which constitute extended continuing involvement under ASC 360-20, it has been determined that the transfer of the Company’s Eagle Ford Shale gathering and treating systems to EagleHawk should be accounted for as a failed sale of in substance real estate.
As a result of the failed sale, the Company accounts for the continued operations of the gas gathering systems and reflects a financing obligation, representing the proceeds received, under the financing method of real estate accounting. Under the financing method, the historical cost of the Eagle Ford Shale gas gathering systems transferred to EagleHawk is carried at the full historical basis of the assets on the unaudited condensed consolidated balance sheets in “Gas gathering systems and equipment” and depreciated over the remaining useful life of the assets. The financing obligation of approximately $189.9 million as of September 30, 2012 including $2.1 million that has been classified as current, is recorded on the unaudited condensed consolidated balance sheets in “Payable on financing arrangement.” Reductions to the obligation and non cash interest on the financing obligation are tied to the gathering and treating services, as the Company 11
delivers its production through the Eagle Ford Shale gathering and treating systems. Interest and principal are determined based upon the allocable income to Kinder Morgan, and interest is limited up to an amount that is calculated based upon the Company’s weighted average cost of debt as of the date of the transaction. Allocable income in excess of the calculated value is reflected as reductions of principal. Interest is recorded in “Interest expense and other” on the unaudited condensed consolidated statements of operations. Additionally the Company records EagleHawk’s revenues, net of eliminations for intercompany amounts associated with gathering and treating services provided to the Company, and expenses on the unaudited condensed consolidated statements of operations in “Midstream revenues,” “Taxes other than income,”
“Gathering, transportation and other,” “General and administrative,” “Interest expense and other” and “Depletion, depreciation and amortization.”
Hawk Field Services, LLC Joint Venture
On May 21, 2010, Hawk Field Services, a wholly owned subsidiary of Petrohawk, and KM Gathering, formed a new joint venture pursuant to a Formation and Contribution Agreement (Contribution Agreement). The new joint venture entity, KinderHawk, engages in the natural gas midstream business in Northwest Louisiana, focused on the Haynesville and Lower Bossier Shales. Pursuant to the Contribution Agreement, Hawk Field Services contributed to KinderHawk its Haynesville Shale gathering and treating business in Northwest Louisiana, and Kinder Morgan contributed approximately $917 million in cash ($875 million for a 50% membership interest in KinderHawk and $42 million for certain closing adjustments including 2010 capital expenditures through the closing date) to KinderHawk. Each of Hawk Field Services and Kinder Morgan own a 50% membership interest in KinderHawk. KinderHawk distributed approximately $917 million to Hawk Field Services. The joint venture had an economic effective date of January 1, 2010, and Hawk Field Services continued to operate the business until September 30, 2010, at which date Hawk Field Services and Kinder Morgan terminated the transition services agreement and KinderHawk assumed operations of the joint venture. In connection with the joint venture transaction the Company entered into a gathering agreement with KinderHawk which requires the Company to deliver natural gas to KinderHawk from dedicated lease acreage for the life of the dedicated lease acreage, or approximately 30 years, and includes a minimum delivery commitment over a five-year period.
The KinderHawk joint venture is accounted for as a failed sale of in substance real estate under the provisions of ASC 360-20. ASC 360-20 establishes standards for recognition of profit on all real estate sales transactions other than retail land sales, without regard to the nature of the seller’s business. In making the determination of whether a transaction qualifies, in substance, as a sale of real estate, the nature of the entire real estate being sold is considered, including the land plus the property improvements and the integral equipment. The Haynesville Shale gathering and treating system, consists of right of ways, pipelines and processing facilities. Due to the gathering agreement which constitutes extended continuing involvement under ASC 360-20, it has been determined that the contribution of the Company’s Haynesville Shale gathering and treating system to form KinderHawk should be accounted for as a failed sale of in substance real estate.
As a result of the failed sale the Company accounts for the continued operations of the gas gathering system and reflects a financing obligation, representing the proceeds received, under the financing method of real estate accounting. Under the financing method, the historical cost of the Haynesville Shale gas gathering system contributed to KinderHawk is carried at the full historical basis of the assets on the unaudited condensed consolidated balance sheets in “Gas gathering systems and equipment” and depreciated over the remaining useful life of the assets. The financing obligation of approximately $1.7 billion as of September 30, 2012 including $17.1 million that has been classified as current, is recorded on the unaudited condensed consolidated balance sheets in “Payable on financing arrangement.” Reductions to the obligation and non cash interest on the financing obligation are tied to the gathering and treating services, as the Company delivers natural gas through the Haynesville Shale gathering and treating system. Interest and principal are determined based upon the allocable income to Kinder Morgan, and interest is limited up to an amount that is calculated based upon the Company’s weighted average cost of debt as of the date of the transaction. Allocable income in excess of the calculated value is reflected as reductions of principal. Interest is recorded in “Interest expense and other” on the unaudited condensed consolidated statements of operations. Additionally the Company recorded KinderHawk’s revenues, net of eliminations for intercompany amounts associated with gathering and treating services provided to the Company, and expenses on the unaudited condensed consolidated statements of operations in “Midstream revenues,” “Taxes other than income,”
“Gathering, transportation and other,” “General and administrative,” “Interest expense and other” and “Depletion, depreciation and amortization.”
On July 1, 2011, following the transfer of the Company’s remaining 50% membership interest in KinderHawk to KM Gathering, KinderHawk’s revenues and expenses are no longer recorded in the Company’s unaudited condensed consolidated statements of operations. The historical cost of the Haynesville Shale gas gathering system continues to be carried at the full historical basis of the assets on the unaudited condensed consolidated balance sheet and depreciated over the useful life of the assets.
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3. OIL AND NATURAL GAS PROPERTIES
The Company uses the full cost method of accounting for its investment in oil and natural gas properties. Under this method of accounting, all costs of acquisition, exploration and development of oil and natural gas reserves (including such costs as leasehold acquisition costs, geological expenditures, dry hole costs, tangible and intangible development costs and direct internal costs) are capitalized as the cost of oil and natural gas properties when incurred. To the extent capitalized costs of evaluated oil and natural gas properties, net of accumulated depletion exceed the discounted future net revenues of proved oil and natural gas reserves net of deferred taxes, such excess capitalized costs are charged to expense. Beginning December 31, 2009, full cost companies use the unweighted arithmetic average first day of the month price for oil and natural gas for the 12-month period preceding the calculation date to calculate the future net revenues of proved reserves.
The Company assesses all items classified as unevaluated property on a quarterly basis for possible impairment or reduction in value. The Company assesses properties on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of the following factors, among others: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization.
At September 30, 2012 the ceiling test value of the Company’s reserves was calculated based on the first day average of the 12-months ended September 30, 2012 of the West Texas Intermediate (WTI) spot price of $95.15 per barrel, adjusted by lease or field for quality, transportation fees, and regional price differentials, and the first day average of the 12-months ended September 30, 2012 of the Henry Hub price of $2.84 per million British thermal units (Mmbtu), adjusted by lease or field for energy content, transportation fees, and regional price differentials. Using these prices, the Company’s net book value of oil and natural gas properties at September 30, 2012, did not exceed the ceiling amount. Changes in production rates, levels of reserves, future development costs, and other factors will determine the Company’s actual ceiling test calculation and impairment analyses in future periods.
At September 30, 2011 the ceiling test value of the Company’s reserves was calculated based on the first day average of the 12-months ended September 30, 2011 of the WTI spot price of $94.51 per barrel, adjusted by lease or field for quality, transportation fees, and regional price differentials, and the first day average of the 12-months ended September 30, 2011 of the Henry Hub price of $4.16 per Mmbtu, adjusted by lease or field for energy content, transportation fees, and regional price differentials. Using these prices, the Company’s net book value of oil and natural gas properties at September 30, 2011, did not exceed the ceiling amount.
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4. LONG-TERM DEBT
Long-term debt as of September 30, 2012 and December 31, 2011 consisted of the following:
September 30, December 31, 2012 2011(1) (In thousands)
6.25% $600 million senior notes $ 600,000 $ 600,000 7.25% $1.2 billion senior notes (2) 1,231,157 1,231,780 10.5% $600 million senior notes (3) 568,622 561,250 7.875% $800 million senior notes 799,611 799,611 $ 3,199,390 $ 3,192,641
(1) Table excludes $17.5 million of deferred premiums on derivative contracts which were classified as current at December 31, 2011 and were paid during the first quarter of 2012.
(2) Amount includes a $6.2 million and $6.8 million premium at September 30, 2012 and December 31, 2011, respectively, which was recorded by the Company in conjunction with the issuance of the additional $400 million principal amount. See “7.25% Senior Notes” below for more details.
(3) Amount includes a $21.0 million and $28.4 million discount at September 30, 2012 and December 31, 2011, respectively, recorded by the Company in conjunction with the issuance of the 10.5% $600 million senior notes. See “10.5% Senior Notes” below for more details.
Senior Revolving Credit Facility
Historically, the Company had a credit facility between the Company, each of the lenders from time to time party thereto (the Lenders), BNP Paribas, as administrative agent for the Lenders, Bank of America, N.A. and Bank of Montreal as co-syndication agents for the Lenders, and JPMorgan Chase Bank, N.A. and Wells Fargo Bank, N.A., as co-documentation agents for the Lenders (the Senior Credit Agreement). Effective October 3, 2011, the Company reduced the borrowing base under its Senior Credit Agreement from $2.5 billion to $25 million. At December 31, 2011, the Company had a $3.0 million letter of credit outstanding with a vendor, no borrowings outstanding and $22.0 million of borrowing capacity under the Senior Credit Agreement. Effective February 1, 2012, the $3.0 million letter of credit was terminated and effective March 13, 2012, the Company terminated the Senior Credit Agreement.
The Company’s primary sources of capital and liquidity have historically been internally generated cash flows from operations, proceeds from asset sales and availability under the Senior Credit Agreement. Due to the termination of the Company’s Senior Credit Agreement, future capital resources and liquidity will now be from equity funding by the Parent and the Company’s internally generated cash flows from operations.
6.25% Senior Notes
On May 20, 2011, the Company completed a private placement offering to eligible purchasers of an aggregate principal amount of $600 million of its 6.25% senior notes due 2019 (the 2019 Notes). The 2019 Notes were issued under and are governed by an indenture dated May 20, 2011, between the Company, U.S. Bank Trust National Association, as trustee, and the Company’s subsidiaries named therein as guarantors (the 2019 Indenture). The 2019 Notes were sold to investors at 100% of the aggregate principal amount of the 2019 Notes. The net proceeds from the sale of the 2019 Notes were approximately $589 million (after deducting offering fees and expenses). The proceeds were used to repay borrowings outstanding under the Company’s Senior Credit Agreement and for working capital for general corporate purposes.
The 2019 Notes bear interest at a rate of 6.25% per annum, payable semi-annually on June 1 and December 1 of each year, commencing on December 1, 2011. The 2019 Notes will mature on June 1, 2019. The 2019 Notes are senior unsecured obligations of the Company and rank equally with all of its current and future senior indebtedness. The 2019 Notes are jointly and severally, fully and unconditionally guaranteed on a senior unsecured basis by the Company’s subsidiaries, with the exception of two subsidiaries, as discussed in Note 12, “EagleHawk Field Services.” Petrohawk Energy
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Corporation, the issuer of the 2019 Notes, has no material independent assets or operations apart from the assets and operations of its subsidiaries.
The Company is required to offer to repurchase the 2019 Notes at a purchase price of 101% of the principal amount, plus accrued and unpaid interest, if any, to the redemption date, in the event of a change of control as defined in the 2019 Indenture that is followed by a decline within 90 days in the ratings of the 2019 Notes published by either Moody’s Investor Service, Inc. (Moody’s) or Standard & Poor’s Rating Services (S&P). The Company’s credit rating did not decline in the allotted period of time after the change of control with the closing of the BHP Merger. As a result, no such offer was made. The 2019 Indenture contains covenants that, among other things, restrict or limit the ability of the Company and its subsidiaries to: borrow money; pay dividends on stock; purchase or redeem stock or subordinated indebtedness; make investments; create liens; enter into transactions with affiliates; sell assets; and merge with or into other companies or transfer all or substantially all of the Company’s assets. However, during the fourth quarter of 2011, an Investment Grade Rating Event (as defined in the 2019 Indenture) occurred that resulted in certain covenants in the 2019 Indenture, including covenants relating to incurrence of indebtedness, restricted payments, asset sales and affiliate transactions, being terminated.
7.25% Senior Notes
On August 17, 2010, the Company completed a private placement offering to eligible purchasers of an aggregate principal amount of $825 million of its 7.25% senior notes due 2018 (the initial 2018 Notes) at a purchase price of 100% of the principal amount of the initial 2018 Notes. The initial 2018 Notes were issued under and are governed by an indenture dated August 17, 2010, between the Company, U.S. Bank Trust National Association, as trustee, and the Company’s subsidiaries named therein as guarantors (the 2018 Indenture). The Company applied the net proceeds from the sale of the initial 2018 Notes to redeem its $775 million 9.125% senior notes due 2013.
On January 31, 2011, the Company completed the issuance of an additional $400 million aggregate principal amount of its 7.25% senior notes due 2018 (the additional 2018 Notes) in a private placement to eligible purchasers. The additional 2018 Notes are issued under the same Indenture and are part of the same series as the initial 2018 Notes. The additional 2018 Notes together with the initial 2018 Notes are collectively referred to as the 2018 Notes.
The additional 2018 Notes were sold to Barclays Capital Inc. at 101.875% of the aggregate principal amount of the additional 2018 Notes plus accrued interest. The net proceeds from the sale of the additional 2018 Notes were approximately $400.5 million (after deducting offering fees and expenses). A portion of the proceeds of the additional 2018 Notes were utilized to redeem all of the Company’s outstanding $275 million 7.125% senior notes due 2012.
Interest on the 2018 Notes is payable on February 15 and August 15 of each year, beginning on February 15, 2011. Interest on the 2018 Notes accrued from August 17, 2010, the original issuance date of the series. The 2018 Notes will mature on August 15, 2018. The 2018 Notes are senior unsecured obligations of the Company and rank equally with all of the Company’s current and future senior indebtedness. The 2018 Notes are jointly and severally, fully and unconditionally guaranteed on a senior unsecured basis by the Company’s subsidiaries, with the exception of two subsidiaries, as discussed in Note 12, “EagleHawk Field Services.” Petrohawk Energy Corporation, the issuer of the 2018 Notes, has no material independent assets or operations apart from the assets and operations of its subsidiaries.
The Company is required to offer to repurchase the 2018 Notes at a purchase price of 101% of the principal amount, plus accrued and unpaid interest, if any, to the redemption date, in the event of a change of control as defined in the 2018 Indenture that is followed by a decline within 90 days in the ratings of the 2018 Notes published by either Moody’s or S&P. The Company’s credit rating did not decline in the allotted period of time after the change of control with the closing of the BHP Merger. As a result, no such offer was made. The 2018 Indenture contains covenants that, among other things, restrict or limit the ability of the Company and its subsidiaries to: borrow money; pay dividends on stock; purchase or redeem stock or subordinated indebtedness; make investments; create liens; enter into transactions with affiliates; sell assets; and merge with or into other companies or transfer all or substantially all of the Company’s assets. However, during the fourth quarter of 2011, an Investment Grade Rating Event (as defined in the 2018 Indenture) occurred that resulted in certain covenants in the 2018 Indenture, including covenants relating to incurrence of indebtedness, restricted payments, asset sales and affiliate transactions, being terminated.
In conjunction with the issuance of the additional 2018 Notes, the Company recorded a premium of $7.5 million to be amortized over the remaining life of the notes utilizing the effective interest rate method. The remaining unamortized premium was $6.2 million at September 30, 2012.
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10.5% Senior Notes
On January 27, 2009, the Company completed a private placement offering to eligible purchasers of an aggregate principal amount of $600 million of its 10.5% senior notes due 2014 (the 2014 Notes). The 2014 Notes were issued under and are governed by an indenture dated January 27, 2009, between the Company, U.S. Bank Trust National Association, as trustee, and the Company’s subsidiaries named therein as guarantors (the 2014 Indenture).
The 2014 Notes bear interest at a rate of 10.5% per annum, payable semi-annually on February 1 and August 1 of each year. The 2014 Notes will mature on August 1, 2014. The Company is required to offer to repurchase the 2014 Notes at a purchase price of 101% of the principal amount, plus accrued and unpaid interest, if any, to the redemption date, in the event of a change of control as defined in the 2014 Indenture. The 2014 Indenture contains covenants that, among other things, restrict or limit the ability of the Company and its subsidiaries to: borrow money; pay dividends on stock; purchase or redeem stock or subordinated indebtedness; make investments; create liens; enter into transactions with affiliates; sell assets; and merge with or into other companies or transfer all or substantially all of the Company’s assets. On September 16, 2011, the Company initiated an offer to repurchase the 2014 Notes, in accordance with the terms of the 2014 Indenture, due to the change of control resulting from the acquisition of the Company by BHP Billiton Limited. The holders of the 2014 Notes had until November 9, 2011 to tender their 2014 Notes. On November 14, 2011, the Company paid principal and interest of $10.8 million to repurchase a portion of the 2014 Notes at the request of the bondholders. The 2014 Notes are senior unsecured obligations of the Company and rank equally with all of its current and future senior indebtedness. The 2014 Notes are jointly and severally, fully and unconditionally guaranteed on a senior unsecured basis by the Company’s subsidiaries, with the exception of two subsidiaries, as discussed in Note 12, “EagleHawk Field Services.” Petrohawk Energy Corporation, the issuer of the 2014 Notes, has no material independent assets or operations apart from the assets and operations of its subsidiaries.
In conjunction with the issuance of the 2014 Notes, the Company recorded a discount of $52.3 million to be amortized over the remaining life of the notes utilizing the effective interest rate method. The remaining unamortized discount was $21.0 million at September 30, 2012.
7.875% Senior Notes
On May 13, 2008 and June 19, 2008, the Company issued $500 million principal amount and $300 million principal amount, respectively, of its 7.875% senior notes due 2015 (the 2015 Notes). The 2015 Notes were issued under and are governed by an indenture dated May 13, 2008, between the Company, U.S. Bank Trust National Association, as trustee, and the Company’s subsidiaries named therein as guarantors (the 2015 Indenture).
The 2015 Notes bear interest at a rate of 7.875% per annum, payable semi-annually on June 1 and December 1 of each year. The 2015 Notes will mature on June 1, 2015. The Company is required to offer to repurchase the 2015 Notes at a purchase price of 101% of the principal amount, plus accrued and unpaid interest, if any, to the redemption date, in the event of a change of control as defined in the 2015 Indenture. The 2015 Indenture contains covenants that, among other things, restrict or limit the ability of the Company and its subsidiaries to: borrow money; pay dividends on stock; purchase or redeem stock or subordinated indebtedness; make investments; create liens; enter into transactions with affiliates; sell assets; and merge with or into other companies or transfer all or substantially all of the Company’s assets. On September 16, 2011, the Company initiated an offer to repurchase the 2015 Notes, in accordance with the terms of the 2015 Indenture, due to the change of control resulting from the acquisition of the Company by BHP Billiton Limited. The holders of the 2015 Notes had until November 9, 2011 to tender their 2015 Notes. On November 14, 2011, the Company paid principal and interest of $0.4 million to repurchase a portion of the 2015 Notes at the request of the bondholders. The 2015 Notes are senior unsecured obligations of the Company and rank equally with all of its current and future senior indebtedness. The 2015 Notes are jointly and severally, fully and unconditionally guaranteed on a senior unsecured basis by the Company’s subsidiaries, with the exception of two subsidiaries, as discussed in Note 12, “EagleHawk Field Services.” Petrohawk Energy Corporation, the issuer of the 2015 Notes, has no material independent assets or operations apart from the assets and operations of its subsidiaries.
Debt Issuance Costs
The Company capitalizes certain direct costs associated with the issuance of long-term debt. In the first quarter of 2012, the Company wrote off $0.2 million of debt issuance costs in conjunction with the termination of the Company’s Senior Credit Agreement. At September 30, 2012 and December 31, 2011, the Company had approximately $38.4 million and $45.5 million, respectively, of debt issuance costs remaining that are being amortized over the lives of the respective debt.
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5. FAIR VALUE MEASUREMENTS
Pursuant to ASC 820, Fair Value Measurements and Disclosures (ASC 820) the Company’s determination of fair value incorporates not only the credit standing of the counterparties involved in transactions with the Company resulting in receivables on the Company’s unaudited condensed consolidated balance sheets, but also the impact of the Company’s nonperformance risk on its own liabilities. ASC 820 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. The Company classifies fair value balances based on the observability of those inputs.
The following tables set forth by level within the fair value hierarchy the Company’s financial assets and liabilities that were accounted for at fair value as of December 31, 2011. There were no financial assets or liabilities that were accounted for at fair value as of September 30, 2012, as the Company terminated its existing derivative contracts during the first quarter of 2012. See further discussion of the termination of the Company’s derivative contracts in Note 8, “Derivatives.” As required by ASC 820, a financial instrument’s level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There were no transfers between fair value hierarchy levels for the nine months ended September 30, 2012 and for the year ended December 31, 2011.
December 31, 2011
Level 1 Level 2 Level 3 Total (In thousands)
Assets:
Receivables from derivative contracts $ —$ 376,731 $ —$ 376,731 Liabilities: Liabilities from derivative contracts $ —$ 40,673 $ —$ 40,673
Derivatives listed above included collars and swaps that were carried at fair value. The Company records the net change in the fair value of these positions in “Net gain (loss) on derivative contracts” in the Company’s unaudited condensed consolidated statements of operations. The Company is able to value the assets and liabilities based on observable market data for similar instruments, which resulted in the Company reporting its derivatives as Level 2. This observable data includes the forward curve for commodity prices based on quoted markets prices and implied volatility factors related to changes in the forward curves.
As of December 31, 2011, the Company’s derivative contracts were with major financial institutions with investment grade credit ratings which are believed to have a minimal credit risk. As such, the Company is exposed to credit risk to the extent of nonperformance by the counterparties in the derivative contracts discussed above; however, the Company does not anticipate such nonperformance. Each of the counterparties to the Company’s derivative contracts was a lender in the Company’s Senior Credit Agreement. The Company did not post collateral under any of these contracts as they were secured under the Senior Credit Agreement.
As discussed in Note 2, “Acquisitions and Divestitures,” the Company acquired additional interests primarily in the Hawkville Field of the Eagle Ford Shale from CEU Hawkville, LLC on December 22, 2011 for $90 million before customary closing adjustments. The Company recorded the estimated fair values of the assets acquired and liabilities assumed at December 22, 2011, which primarily consisted of oil and natural gas properties of $90.1 million and asset retirement obligations of $0.3 million in accordance with ASC 805.
The following disclosure of the estimated fair value of financial instruments is made in accordance with the requirements of ASC 825, Financial Instruments. The estimated fair value amounts have been determined at discrete points in time based on relevant market information. These estimates involve uncertainties and cannot be determined with precision. The estimated fair value of cash, accounts receivable and accounts payable approximates their carrying value due to their short-term nature. The estimated fair value of the Company’s Senior Credit Agreement approximated carrying value because the facility’s interest rate approximated current market rates. The following table presents the estimated fair values of the
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Company’s fixed interest rate, long-term debt instruments as of September 30, 2012 and December 31, 2011 (excluding premiums and discounts and deferred premiums on derivative contracts):
September 30, 2012 December 31, 2011 Carrying Estimated Carrying Estimated Debt Amount Fair Value Amount Fair Value (In thousands)
6.25% $600 million senior notes $ 600,000 $ 676,680 $ 600,000 $ 661,500 7.25% $1.2 billion senior notes 1,225,000 1,392,482 1,225,000 1,398,668 10.5% $600 million senior notes 589,640 640,054 589,640 659,660 7.875% $800 million senior notes 799,611 835,593 799,611 853,585 $ 3,214,251 $ 3,544,809 $ 3,214,251 $ 3,573,413
The fair values of the Company’s fixed interest debt instruments were calculated using quoted market prices based on trades of such debt as of September 30, 2012 and December 31, 2011.
6. ASSET RETIREMENT OBLIGATIONS
For wells drilled, the Company records an asset retirement obligation (ARO) when the total depth of a drilled well is reached and the Company can reasonably estimate the fair value of an obligation to perform site reclamation, dismantle facilities or plug and abandon costs. For gas gathering systems and equipment, the Company records an ARO when the system is placed in service and the Company can reasonably estimate the fair value of an obligation to perform site reclamation and other necessary work. The Company records the ARO liability on the unaudited condensed consolidated balance sheets and capitalizes the cost in “Oil and natural gas properties” or “Gas gathering systems and equipment” during the period in which the obligation is incurred. The Company records the accretion of its ARO liabilities in “Depletion, depreciation and amortization” expense in the unaudited condensed consolidated statements of operations. The additional capitalized costs are depreciated on a unit-of-production basis or straight-line basis.
The Company recorded the following activity related to its ARO liability for the nine months ended September 30, 2012 (in thousands):
Liability for asset retirement obligation as of December 31, 2011 $ 52,317 Additions 6,687 Accretion expense 2,027 Revisions in estimated cash flows (12,532) Liability for asset retirement obligation as of September 30, 2012 $ 48,499
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7. COMMITMENTS AND CONTINGENCIES Commitments
The Company leases corporate office space in Houston, Texas and Tulsa, Oklahoma as well as a number of other field office locations. In addition, the Company has lease commitments related to certain vehicles, machinery and equipment under long-term operating leases. Rent expense was $7.6 million and $5.9 million for the nine months ended September 30, 2012 and 2011, respectively.
As of September 30, 2012, the Company had the following commitments:
Total Obligation Years Amount(1) Remaining (in thousands)
Gathering and transportation commitments $ 3,084,579 17 Drilling rig commitments 909,312 6 Non-cancelable operating leases 22,705 5 Pipeline and well equipment obligations 170,861 1 other things, rental equipment obligations, obtaining and processing seismic data and fracture stimulation services) 27,608 1 Total commitments $ 4,215,065
As part of the KinderHawk transaction, one of the Company’s gathering and transportation commitments is the obligation to deliver to KinderHawk agreed upon minimum annual quantities of natural gas from the Company’s operated wells producing from the Haynesville and Lower Bossier Shales, within specified acreage in Northwest Louisiana through May 2015, or in the alternative, pay an annual true-up fee to KinderHawk if such minimum annual quantities are not delivered. This minimum annual quantities commitment is not included in the table above. The Company’s obligation to deliver minimum annual quantities of natural gas to KinderHawk through May 2015 remains in effect following the transfer of the Company’s remaining 50% membership interest in KinderHawk on July 1, 2011. The minimum annual quantities per contract year are as follows:
Minimum Annual Contract Year Quantity (Bcf)
Year 1 (partial)—2010 . 81.090 Year 2—2011 . 152.899 Year 3—2012 . 238.595 Year 4—2013 . 324.047 Year 5—2014 . 368.614 Year 6 (partial)—2015 . 143.066
These volumes represent 50% of the Company’s anticipated production from the specified acreage at the time the Company entered into the contract. Production from this acreage has been significantly in excess of these volumes since the inception of the agreement, and the Company has not been obligated to pay a true-up fee to date.
The Company pays KinderHawk negotiated gathering and treating fees, subject to an annual inflation adjustment factor. The gathering fee at the time the Company entered into the contract was equal to $0.34 per Mcf of natural gas delivered at KinderHawk’s 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. In the event that annual natural gas deliveries are ever less than the minimum annual quantity per contract year set forth in the table above, the Company’s true-up fee obligation would be determined by subtracting the quantity delivered from the minimum annual quantity for the applicable contract year and multiplying the positive difference by the sum of the gathering fee in effect on the last day of such year plus the average monthly treating fees for such year. For example, if the quantity of natural gas delivered in 2010 were 50 Bcf less than the minimum annual quantity for such year and the year-end gathering fee was $0.34 per Mcf and the average treating fee for the period was $0.345 per Mcf, the true-up fee would be $34.3 million.
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As previously discussed, the Company has certain amounts associated with the sale of its interests in KinderHawk and EagleHawk recorded as financing obligations in the unaudited condensed consolidated balance sheets, which are not reflected in the amounts shown in the table above. The balance of the Company’s financing obligations as of September 30, 2012 and December 31, 2011, was approximately $1.9 billion and $1.8 billion, respectively, of which approximately $19.2 million and $17.6 million was classified as current for the respective periods.
Contingencies
From time to time, the Company may be a plaintiff or defendant in a pending or threatened legal proceeding arising in the normal course of its business. All known liabilities are accrued based on the Company’s best estimate of the potential loss. While the outcome and impact of currently pending legal proceedings cannot be determined, the Company’s management and legal counsel believe that the resolution of these proceedings through settlement or adverse judgment will not have a material adverse effect on the Company. Please refer to Item 3. Legal Proceedings in the Company’s Annual Report on Form 10-K for the year ended December 31, 2011, for further information on pending cases.
8. DERIVATIVES
The Company is exposed to certain risks relating to its ongoing business operations, such as commodity price risk and interest rate risk. Derivative contracts were utilized to economically hedge the Company’s exposure to price fluctuations and reduce the variability in the Company’s cash flows associated with anticipated sales of future oil, natural gas and natural gas liquids production. Historically, the Company has generally hedged a substantial, but varying, portion of anticipated oil, natural gas and natural gas liquids production and may do so again at some point in the future. Derivatives are carried at fair value on the unaudited condensed consolidated balance sheets, with the changes in the fair value included in the unaudited condensed consolidated statements of operations for the period in which the change occurs.
It has been the Company’s policy to enter into derivative contracts, including interest rate swaps, only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers. Each of the counterparties to the Company’s derivative contracts was a lender in the Company’s Senior Credit Agreement. The Company did not post collateral under any of these contracts as they were secured under the Company’s Senior Credit Agreement.
On December 20, 2011, the Company entered into a Master Transaction Agreement (the MTA) with Barclays Bank PLC (Barclays) in order to facilitate the termination of a portion of its existing derivative positions. During the first quarter of 2012, the Company completed the transaction and all outstanding positions were terminated. As a result, Barclays paid the Company approximately $209 million. In addition, during the first quarter of 2012, the Company received $68.5 million for the termination of its outstanding derivative positions with BNP Paribas.
The Company did not elect to designate any of its historical derivative contracts for hedge accounting. Accordingly, the Company recorded the net change in the mark-to-market valuation of these derivative contracts, as well as all payments and receipts on settled derivative contracts, in “Net gain (loss) on derivatives contracts” on the unaudited condensed consolidated statements of operations.
At September 30, 2012, the Company had no open commodity derivative contracts. At December 31, 2011, the Company had 63 open commodity derivative contracts summarized in the tables below: 38 natural gas collar arrangements, 11 natural gas swap arrangements and 14 crude oil collar arrangements. Derivative commodity contracts in 2012 through the date of termination and in 2011 settled based on NYMEX WTI and Henry Hub prices, which may have differed from the actual price received by the Company for the sale of its oil and natural gas production.
All derivative contracts are recorded at fair market value in accordance with ASC 815 and ASC 820 and included in the unaudited condensed consolidated balance sheets as assets or liabilities. The following table summarizes the location and fair value amounts of all derivative contracts in the unaudited condensed consolidated balance sheets as of September 30, 2012 and December 31, 2011:
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Derivatives not Asset derivative contracts Liability derivative contracts
designated as hedging September 30, December 31, September 30, December 31,
contracts under ASC 815 Balance sheet location 2012 2011 Balance sheet location 2012 2011
(In thousands) (In thousands)
Current assets—receivables from Current liabilities—liabilities
Commodity contracts derivative contracts $ — $ 371,584 from derivative contracts $ — $ (40,673)
Other noncurrent assets— Other noncurrent liabilities—
receivables from derivative liabilities from derivative
Commodity contracts contracts — 5,147 contracts — -
Total derivatives not designated as hedging contracts under
ASC 815 $ — $ 376,731 $ — $ (40,673)
Derivatives not Asset derivative contracts Liability derivative contracts designated as hedging September 30, December 31, September 30, December 31, contracts under ASC 815 Balance sheet location 2012 2011 Balance sheet location 2012 2011 (In thousands) (In thousands)
Current assets—receivables from Current liabilities—liabilities
Commodity contracts derivative contracts $ —$ 371,584 from derivative contracts $ — $ (40,673) Other noncurrent assets—Other noncurrent liabilities—receivables from derivative liabilities from derivative Commodity contracts contracts — 5,147 contracts — —
Total derivatives not designated as hedging contracts under
ASC 815 $ —$ 376,731 $ — $ (40,673)
The following table summarizes the location and amount of the Company’s realized and unrealized gains and losses on derivative contracts in the Company’s unaudited condensed consolidated statements of operations:
Amount of gain or (loss) Amount of gain or (loss) recognized in income on recognized in income on Derivatives not designated as Location of gain or (loss) derivative contracts derivative contracts hedging contracts under ASC recognized in income on three months ended September 30, nine months ended September 815 derivative contracts 2012 2011 2012 2011 (In thousands) (In thousands) Commodity contracts:
Unrealized gain (loss) on Other income (expenses)—net commodity contracts gain (loss) on derivative contracts $ —$ 134,489 $ (336,058) $ 50,580 Realized gain on commodity Other income (expenses)—net contracts gain (loss) on derivative contracts — 64,951 307,798 181,460
Total net gain (loss) on Other income (expenses)—net derivative contracts gain (loss) on derivative contracts $ —$ 199,440 $ (28,260) $ 232,040
At December 31, 2011, the Company had the following open derivative contracts:
December 31, 2011
Floors Ceilings
Volume in Weighted Weighted Mmbtu’s/ Price / Average Price / Average Period Instrument Commodity Bbl’s/Gal’s Price Range Price Price Range Price
January 2012—December 2012 Collars Natural gas 184,830,000 $4.75—$5.00 $ 4.86 $5.70—$8.00 $ 6.55 January 2012—December 2012 Swaps Natural gas 36,600,000 5.05—5.20 5.16 January 2012—December 2012 Collars Crude oil 5,124,000 75.00—90.00 80.71 98.00—130.00 104.27 January 2013—December 2013 Swaps Natural gas 3,650,000 5.40 5.40
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9. STOCKHOLDER’S EQUITY
As discussed in Note 1, “Financial Statement Presentation,” pursuant to the terms of the Merger Agreement on August 20, 2011, Purchaser accepted for payment all shares of the Company’s common stock, approximately 293.9 million shares, representing approximately 97.4% of the total outstanding shares and on August 25, 2011 Purchaser completed a short-form merger under Delaware law of Purchaser with and into the Company, with the Company being the surviving corporation. At the effective time of such merger, each share issued and outstanding immediately prior to the effective time of such merger ceased to be issued and outstanding and were converted into the right to receive an amount in cash equal to the Offer Price, without interest. As a result of such merger, the Company issued 100 shares with par value of $0.001 per share all of which are owned by Parent.
Stock Options and Stock Appreciation Rights
During the nine months ended September 30, 2011, the Company granted stock options covering 2.3 million shares of common stock to employees of the Company. The stock options had exercise prices ranging from $20.57 to $38.21 with a weighted average price of $20.67. In conjunction with the BHP Merger, the Company cancelled all of its unexercised stock options and stock appreciation rights, including vested and unvested, and distributed the excess of $38.75 over the exercise price per unit to each holder, net of applicable withholding taxes. As a result, all of the Company’s remaining unrecognized compensation expense of $25.2 million was accelerated and recognized as stock-based compensation expense in the third quarter of 2011. No stock options or stock appreciation rights remain outstanding as of September 30, 2012.
Restricted Stock
During the nine months ended September 30, 2011, the Company granted 1.3 million shares of restricted stock to employees of the Company and non-employee directors. These restricted shares were granted at prices ranging from $20.57 to $38.21 with a weighted average price of $20.86. In conjunction with the BHP Merger, the Company purchased and cancelled all of the outstanding unvested restricted stock from employees and non-employee directors of the Company, and distributed $38.75 per share to each holder, net of applicable withholding taxes. As a result, all of the Company’s remaining unrecognized compensation expense of $27.3 million was accelerated and recognized as stock-based compensation expense in the third quarter of 2011. No restricted stock remains outstanding as of September 30, 2012.
Assumptions
The assumptions used in calculating the fair value of the Company’s stock-based compensation are disclosed in the following table:
Nine Months Ended September 30, 2011
Weighted average value per option granted during the period $ 10.52 Assumptions (1) : Stock price volatility (2) 58.0% Risk free rate of return 2.01% Expected term 5.0 years
(1) The Company’s estimated future forfeiture rate was approximately 5% based on the Company’s historical forfeiture rate. Calculated using the Black-Scholes fair value based method. The Company did not pay dividends on its common stock.
| (2) |
|
In 2011, the Company used a combination of implied and historic volatility. 22 |
| 10. |
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ADDITIONAL FINANCIAL STATEMENT INFORMATION |
Certain balance sheet amounts are comprised of the following:
September 30, December 31, 2012 2011 (In thousands)
Accounts receivable:
Oil and natural gas revenues $ 217,849 $ 196,662 Joint interest accounts 351,218 182,134 Income and other taxes receivable 4,256 20,795 Other 18,981 10,524 $ 592,304 $ 410,115
Prepaids and other:
Prepaid insurance $ 3,363 $ 8,652 Prepaid drilling costs 23,406 29,013 Other 3,945 4,395 $ 30,714 $ 42,060
Accounts payable and accrued liabilities:
Trade payables $ 275,560 $ 26,977 Revenues and royalties payable 66,998 126,897 Accrued oil and natural gas capital costs 561,126 465,299 Accrued midstream capital costs 68,370 42,620 Accrued interest expense 55,372 67,937 Prepayment liabilities 63,758 49,657 Accrued lease operating expenses 11,457 10,902 Accrued ad valorem taxes payable 20,156 18,972 Accrued production taxes payable 8,774 3,411 Accrued gathering, transportation and other exp 53,282 55,513 Accrued employee compensation 30,985 40,682 Income taxes payable 30,709 2,317 Other 32,212 52,517 $ 1,278,759 $ 963,701
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| 11. |
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DISCONTINUED OPERATIONS |
On December 22, 2010, the Company completed the sale of its interest in natural gas properties and other operating property and equipment in the Fayetteville Shale. On January 7, 2011, the Company completed the sale of its midstream assets in the Fayetteville Shale. For all periods presented, the Company classified the operations associated with the Fayetteville Shale gas gathering systems and equipment, which are part of the Company’s midstream operations segment, and the Fayetteville Shale other operating property and equipment, which are part of the Company’s oil and natural gas production segment, as “Loss from discontinued operations, net of income taxes” in the unaudited condensed consolidated statements of operations.
On March 1, 2011, the Company completed the sale of its interest in the Buffalo Hump Ranch located in Van Buren County, Arkansas for approximately $2.1 million in cash. Proceeds from the sale were recorded as a reduction to the carrying value of the land. A loss on the sale of approximately $4.3 million was recorded during the first quarter of 2011 in “Loss from discontinued operations, net of income taxes” in the unaudited condensed consolidated statements of operations. The transaction had an effective date of March 1, 2011.
The following table contains summarized income statement information for the Fayetteville Shale midstream operations and other operating property and equipment for the period indicated (in thousands):
Three Months Ended Nine Months Ended September 30, 2011 September 30, 2011
Operating revenues $ —$ 153 Operating expenses — 43 Loss on sale (67) (5,289) Loss from discontinued operations, before income taxes (67) (5,179) Income tax benefit 25 1,978 Loss from discontinued operations, net of income taxes $ (42) $ (3,201)
| 12. |
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EAGLEHAWK FIELD SERVICES |
As discussed in Note 2, “Acquisitions and Divestitures,” on July 1, 2011, the Company along with its subsidiaries Hawk Field Services and EagleHawk, closed previously announced transactions with Eagle Gathering, an affiliate of Kinder Morgan, including the transfer by Hawk Field Services of a 25% interest in EagleHawk to Eagle Gathering in exchange for cash consideration of approximately $93 million.
EagleHawk, which is managed by Hawk Field Services, owns and operates the gathering and treating assets and business serving the Company’s Hawkville and Black Hawk Fields in the Eagle Ford Shale. The Company has dedicated its production from its Eagle Ford Shale leases pursuant to gathering and treating agreements with EagleHawk.
EagleHawk is accounted for as a failed sale of in substance real estate under the provisions of ASC 360-20. ASC 360-20 establishes standards for recognition of profit on all real estate sales transactions other than retail land sales, without regard to the nature of the seller’s business. In making the determination as to whether a transaction qualifies, in substance, as a sale of real estate, the nature of the entire real estate being sold is considered, including the land plus the property improvements and the integral equipment. The Eagle Ford Shale gathering and treating systems consist of right of ways, pipelines and processing facilities. The Company concluded that the gathering agreements constitute extended continuing involvement under ASC 360-20, and have therefore determined that the transfer of the Company’s Eagle Ford Shale gathering and treating systems to EagleHawk should be accounted for as a failed sale of in substance real estate.
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The following table presents statement of operations information for EagleHawk for the three and nine months ended September 30, 2012 and 2011:
Three Months Ended September 30, Nine Months Ended September 30, 2012 2011 2012 2011 Operating revenues:
Midstream $ 14,476 $ 3,907 $ 39,644 $ 3,907 Total operating revenues 14,476 3,907 39,644 3,907
Operating expenses:
Taxes other than income 1,108 323 2,970 323 Gathering, transportation and other 6,355 3,291 17,740 3,291 General and administrative 469 440 1,413 440 Depletion, depreciation and amortization 4,601 1,951 12,244 1,951 Total operating expenses 12,533 6,005 34,367 6,005 Income from operations 1,943 (2,098) 5,277 (2,098)
Other income (expenses):
Interest expense and other (3,980) (1,547) (11,331) (1,547) Total other income (expenses) (3,980) (1,547) (11,331) (1,547) Loss from continuing operations before income taxes (2,037) (3,645) (6,054) (3,645) Income tax benefit 801 1,333 2,206 1,333 Net loss $ (1,236) $ (2,312) $ (3,848) $ (2,312)
The following table presents balance sheet information for EagleHawk as of September 30, 2012 and December 31, 2011:
September 30, December 31, 2012 2011 Current assets:
Cash $ 32,842 $ 34,736 Accounts receivable 16,206 8,025 Prepaids and other 99 73 Total current assets 49,147 42,834
Other operating property and equipment:
Gas gathering systems and equipment 687,357 447,335 Other operating assets 1,027 1,022 Gross other operating property and equipment 688,384 448,357 Less—accumulated depreciation (22,172) (10,203) Net other operating property and equipment 666,212 438,154
Other noncurrent assets:
Deferred income taxes 2,206 2,279 Total assets $ 717,565 $ 483,267
Current liabilities:
Accounts payable and accrued liabilities $ 84,161 $ 42,109 Total current liabilities 84,161 42,109
Other noncurrent liabilities
Payable to affiliate 200,916 122,477 Asset retirement obligations 13,009 9,775 Other 7 5 Commitments and contingencies
Members’ equity:
Additional paid-in capital 429,697 312,999 Accumulated deficit (10,225) (4,098) Total members’ equity 419,472 308,901
Total liabilities and Members’ equity $ 717,565 $ 483,267
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The following table presents cash flow statement information for EagleHawk for the nine months ended September 30, 2012 and 2011:
Nine Months Ended September 30, 2012 2011
Cash flows from operating activities:
Net loss $ (3,848) $ (2,312) Adjustments to reconcile net loss to net cash provided by operating activities: Depletion, depreciation and amortization 12,244 1,951 Income tax benefit (2,206) (1,333) Other operating 128 83 Change in assets and liabilities: Accounts receivable (8,181) (5,352) Prepaid and other (152) (126) Accounts payable and accrued liabilities 24,092 4,598 Net cash provided by (used in) operating activities 22,077 (2,491)
Cash flows from investing activities:
Other operating property and equipment capital expenditures (219,108) (67,896) Net cash used in investing activities (219,108) (67,896)
Cash flows from financing activities:
Proceeds from borrowings — 65,000 Repayment of borrowings — (8,500) Debt issuance costs — (401) Payable to affiliate 78,439 7,625 Contributions from affiliate 149,338 6,149 Distributions to affiliate (32,640) (6,149) Net cash provided by financing activities 195,137 63,724
Net decrease in cash (1,894) (6,663) Cash at beginning of period 34,736 -Cash at end of period $ 32,842 $ (6,663)
As discussed in Note 4, “Long-Term Debt,” Petrohawk Energy Corporation has issued senior notes that remain outstanding as of the date of this report. Petrohawk has no material independent assets or operations and its senior notes have been guaranteed on an unconditional, joint and several basis, by all of its wholly-owned subsidiaries that have assets or operations. EagleHawk, which is not wholly-owned, and one of the Company’s other subsidiaries, Proliq, Inc., are designated as unrestricted subsidiaries for purposes of the Company’s Senior Credit Agreement and indentures. Proliq, Inc. has no assets or operations.
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MANAGEMENT’S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS
The following narrative is intended to assist in understanding our results of operations for the nine months ended September 30, 2012 and 2011 and should be read in conjunction with our unaudited condensed consolidated financial statements and the notes thereto included in this report and with the consolidated financial statements, notes and management’s narrative analysis included in our Annual Report on Form 10-K for the year ended December 31, 2011.
Statements in this narrative may be forward-looking. These forward-looking statements involve risks and uncertainties, including those discussed below, which could cause actual results to differ from those expressed.
Overview
We are an oil and natural gas company engaged in the exploration, development and production of predominately natural gas properties located in the United States. As further discussed in Note 1 “Financial Statement Presentation,” on August 25, 2011, BHP Billiton Limited, a corporation organized under the laws of Victoria, Australia (BHP Billiton Limited), acquired 100% of our outstanding shares of common stock through the merger of a wholly owned subsidiary of BHP Billiton Petroleum (North America) Inc., a Delaware corporation and wholly owned subsidiary of BHP Billiton Limited, with and into Petrohawk, with Petrohawk continuing as the surviving entity. At the date of this report, Petrohawk remains an indirect, wholly owned subsidiary of BHP Billiton Limited.
Our financial results depend upon many factors, but are largely driven by the volume of our oil and natural gas production and the price that we receive for that production. Our production volumes will decline as reserves are depleted unless we expend capital in successful development and exploration activities or acquire properties with existing production. The amount we realize for our production depends predominantly upon commodity prices, which are affected by changes in market demand and supply, as impacted by overall economic activity, weather, pipeline capacity constraints, inventory storage levels, basis differentials and other factors. Accordingly, finding and developing oil and natural gas reserves at economical costs is critical to our long-term success.
Our cash flows are subject to a number of variables including our level of oil and natural gas production and commodity prices, as well as various economic conditions that have historically affected the oil and natural gas industry. If natural gas prices remain at their current levels for a prolonged period of time or if oil and natural gas prices decline, our ability to fund our capital expenditures, reduce debt, meet our financial obligations and become profitable may be materially impacted. Our primary sources of capital and liquidity have historically been internally generated cash flows from operations, proceeds from asset sales and availability under our Senior Credit Agreement. Our future capital resources and liquidity will be from internally generated cash flows from operations and funding from our Parent.
Contractual Obligations
We have no material changes in our long-term commitments associated with our capital expenditure plans or operating agreements other than those described below. Our level of capital expenditures will vary in future periods depending on the success we experience in our acquisition, development and exploration activities, oil and natural gas price conditions and other related economic factors. Currently no sources of liquidity or financing are provided by off-balance sheet arrangements or transactions with unconsolidated, limited-purpose entities. The following table summarizes our contractual obligations and commitments as of September 30, 2012:
Total Obligation Years Amount(1) Remaining (in thousands)
Gathering and transportation commitments $ 3,084,579 17 Drilling rig commitments 909,312 6 Non-cancelable operating leases 22,705 5 Pipeline and well equipment obligations 170,861 1 Various contractual commitments (including, among other things, rental equipment obligations, obtaining and processing seismic data and fracture stimulation services) 27,608 1 Total commitments $ 4,215,065
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For more information on amounts not included in the table above, refer to Note 7, “Commitments and Contingencies.”
Critical Accounting Policies and Estimates
Our discussion and analysis of our financial condition and results of operations are based upon the unaudited condensed consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. Preparation of these unaudited condensed consolidated financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. There have been no material changes to our critical accounting policies from those described in our Annual Report on Form 10-K for the year ended December 31, 2011.
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Results of Operations
Nine Months Ended September 30, 2012 and 2011
We reported a loss from continuing operations, net of income taxes of $134.4 million for the nine months ended September 30, 2012 compared to income from continuing operations, net of income taxes of $127.7 million for the same period in 2011, resulting in a net change of $262.1 million. The following table summarizes key items of comparison and their related change for the periods indicated.
Nine Months Ended September 30,
In thousands (except per unit and per Mcfe amounts) 2012 2011 Change
(Loss) income from continuing operations, net of income taxes $ (134,440) $ 127,679 $ (262,119) Operating revenues: Oil and natural gas 1,467,749 1,285,225 182,524 Marketing 5,262 295,946 (290,684) Midstream 58,582 12,167 46,415 Operating expenses: Marketing 4,976 322,266 (317,290) Production: Lease operating 67,068 43,670 23,398 Workover and other 12,652 12,047 605 Taxes other than income 47,071 48,142 (1,071) Gathering, transportation and other 233,745 99,736 134,009 General and administrative: General and administrative 134,745 171,260 (36,515) Stock-based compensation — 53,203 (53,203) Depletion, depreciation and amortization: Depletion – Full cost 843,324 565,109 278,215 Depreciation—Midstream 23,640 16,592 7,048 Depreciation – Other 21,301 7,307 13,994 Accretion expense 2,027 1,499 528 Impairment of capitalized software costs 1,351 — 1,351 Other income (expenses): Net (loss) gain on derivative contracts (28,260) 232,040 (260,300) Interest expense and other (322,943) (283,297) (39,646) (Loss) income from continuing operations before income taxes (211,510) 201,250 (412,760) Income tax benefit (provision) 77,070 (73,571) 150,641
Production:
Natural gas – Mmcf 261,191 226,907 34,284 Crude oil – MBbl 6,976 3,069 3,907 Natural gas liquids—MBbl 4,194 1,886 2,308 Natural gas equivalent – Mmcfe(1) 328,211 256,637 71,574 Average daily production – Mmcfe(1) 1,198 940 258
Average price per unit(2):
Natural gas price—Mcf $ 2.40 $ 4.06 $ (1.66) Crude oil price—Bbl 98.31 86.46 11.85 Natural gas liquids price—Bbl 35.15 49.12 (13.97) Natural gas equivalent price—Mcfe(1) 4.45 4.98 (0.53)
Average cost per Mcfe:
Production:
Lease operating 0.20 0.17 0.03 Workover and other 0.04 0.05 (0.01) Taxes other than income 0.14 0.19 (0.05) Gathering, transportation and other 0.71 0.39 0.32 General and administrative: General and administrative 0.41 0.67 (0.26) Stock-based compensation — 0.21 (0.21) Depletion 2.57 2.20 0.37
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(1) Oil and natural gas liquids are converted to equivalent gas production using a 6:1 equivalent ratio. This ratio does not assume price equivalency and given price differentials, the price for a barrel of oil equivalent for natural gas may differ significantly from the price for a barrel of oil.
(2) Amounts exclude the impact of cash paid/received on settled contracts as we did not elect to apply hedge accounting.
For the nine months ended September 30, 2012, oil and natural gas revenues increased $183 million from the same period in 2011, to $1.5 billion. The increase was primarily due to the increase in our equivalent production of 71,574 Mmcfe, or 28% over the nine months ended September 30, 2011, resulting from our drilling successes in resource plays in Louisiana and Texas. Increased production contributed approximately $356 million in revenues for the nine months ended September 30, 2012. This increase was partially offset by a decrease of $0.53 per Mcfe in our realized average price to $4.45 per Mcfe from $4.98 per Mcfe in the prior year period. The decrease in realized average prices led to a decrease in oil and natural gas revenues of approximately $174 million.
Prior to July 1, 2011, a subsidiary of ours purchased and sold our own and third party natural gas produced from wells which we and third parties operate. Effective July 1, 2011, our marketing subsidiary ceased its marketing operations. The revenues and expenses related to these marketing activities were reported on a gross basis as part of operating revenues and operating expenses in historical periods. Marketing revenues were recorded at the time natural gas was physically delivered to third parties at a fixed or index price. Marketing expenses attributable to gas purchases were recorded as our subsidiary took physical title to natural gas and transported the purchased volumes to the point of sale. Subsequent to July 1, 2011, we no longer bought or sold third party volumes from wells we and third parties operated. As a result, certain items previously recorded to “Marketing revenues” are no longer reported while others are now recorded to “Oil and natural gas revenues” on the unaudited condensed consolidated statements of operations. In addition, certain charges previously reported in “Marketing expenses” are no longer reported while others are now recorded to “Gathering, transportation and other” on the unaudited condensed consolidated statements of operations. For the nine months ended September 30, 2012, we had income before income taxes of $0.3 million compared to a loss before income taxes of $26.3 million in the prior year period.
We had gross revenues from our midstream segment of $99.1 million for the nine months ended September 30, 2012 compared to the same period in 2011 of $65.5 million, an increase of $33.6 million. The increase in gross revenues from our midstream business primarily relates to increased volumes from our gathering and treating system in the Eagle Ford Shale. In accordance with the financing method for a failed sale of in substance real estate we record EagleHawk’s revenues, and through July 1, 2011 we recorded KinderHawk’s revenues, net of eliminations for intercompany amounts associated with gathering and treating services provided to us on the unaudited condensed consolidated statements of operations. Gross revenues of $99.1 million included $40.5 million of intercompany revenues that were eliminated in consolidation. On a net basis, we had revenues of $58.6 million for the nine months ended September 30, 2012, an increase of $46.4 million from the prior year. This increase is attributed to increased volumes from our gathering and treating system in the Eagle Ford Shale offset by the transfer of our remaining 50% membership interest in KinderHawk on July 1, 2011.
Lease operating expenses increased $23.4 million for the nine months ended September 30, 2012 primarily due to our 28% increase in natural gas equivalent production as a result of our drilling successes in resource plays in Louisiana and Texas. On a per unit basis, lease operating expenses increased $0.03 per Mcfe to $0.20 per Mcfe compared to $0.17 per Mcfe in the prior year. This increase on a per unit basis is primarily due to the increase in our liquids production which typically has a higher operating cost per equivalent unit.
Gathering, transportation and other expense increased $134.0 million for the nine months ended September 30, 2012 as compared to the same period in 2011 primarily due to our 28% increase in production in 2012. On a per unit basis, gathering transportation and other increased $0.32 per Mcfe from $0.39 per Mcfe in 2011 to $0.71 per Mcfe in 2012. This increase on a per unit basis is primarily attributable to our rising liquids production and the costs associated with treating and transporting the liquids to profitable market locations.
General and administrative expense for the nine months ended September 30, 2012 decreased $36.5 million as compared to the same period in 2011. In the prior year, in conjunction with the BHP Merger, we paid an advisory service fee of $30.2 million. We also incurred professional and legal fees of approximately $8.1 million related to the BHP Merger in the third quarter of 2011.
Stock-based compensation expense for the nine months ended September 30, 2012 was zero compared to the prior year period expense of $53.2 million. On August 25, 2011, BHP Billiton Limited acquired 100% of our outstanding shares of 30
common stock through the merger of a wholly owned subsidiary of BHP Billiton Petroleum (North America) Inc. with and into us. In conjunction with the BHP Merger, we cancelled all unexercised stock options and stock appreciation rights, both vested and unvested, outstanding under our employee and nonemployee equity incentive plans in exchange for a cash payment equal to $38.75 for each share of common stock underlying such option or stock appreciation right, less the applicable exercise price per share and net of withholding taxes. As a result, all of the remaining unrecognized compensation expense was accelerated and recognized as stock-based compensation expense in the third quarter of 2011.
Depletion for oil and natural gas properties is calculated using the unit of production method, which depletes the capitalized costs associated with evaluated properties plus future development costs based on the ratio of production volume for the current period to total remaining reserve volume for the evaluated properties. Depletion expense increased $278.2 million for the nine months ended September 30, 2012 from the same period in 2011, to $843.3 million. On a per unit basis, depletion expense increased $0.37 per Mcfe to $2.57 per Mcfe. The increase on a per unit basis is primarily due to our 2011 and 2012 capital expenditures program.
Depreciation expense associated with our gas gathering systems increased $7.0 million to $23.6 million for the nine months ended September 30, 2012. The increase was due to the growth in our midstream operations from capital spending over the course of the year, as well as the contribution of the gas gathering systems and treating facilities in the Haynesville Shale to KinderHawk and the transfer of a 25% interest in EagleHawk to Eagle Gathering. The KinderHawk and EagleHawk joint ventures are accounted for in accordance with the financing method for a failed sale of in substance real estate. Under the financing method, the historical costs of the Haynesville Shale and Eagle Ford Shale gas gathering systems are carried at the full historical basis of the assets on the unaudited condensed consolidated balance sheets and depreciated over the remaining useful life of the assets. We depreciate our gas gathering systems over a 30 year useful life commencing on the estimated placed in service date.
During the first quarter of 2012, we made the decision to cease implementation of a new budgeting software program. As such, we impaired the capitalized costs associated with this software implementation in the first quarter of 2012. Approximately $1.3 million was recorded to “Impairment of capitalized software costs” in the unaudited condensed consolidated statements of operations during the period the impairment was recognized.
Historically, we have entered into derivative commodity instruments to economically hedge our exposure to price fluctuations on our anticipated oil, natural gas, and natural gas liquids production. We did not elect to designate any positions as cash flow hedges for accounting purposes, and accordingly, we recorded the net change in the mark-to-market value of these derivative contracts in the unaudited condensed consolidated statements of operations. On December 20, 2011, we entered into a Master Transaction Agreement (the MTA) with Barclays Bank PLC (Barclays) in order to facilitate the termination of a portion of our existing derivative positions. As part of the MTA, we entered into certain derivative transactions with Barclays with equal and opposite economic terms from the majority of our existing derivative positions (Mirror Trades). During the first quarter of 2012, we novated the existing derivative positions to Barclays and terminated the existing derivative positions as well as the Mirror Trades and Barclays paid us approximately $209 million. In addition, during the first quarter of 2012, we received $68.5 million for the termination of our outstanding derivative positions with BNP Paribas. In the nine months ended September 30, 2012, we recorded a net derivative loss of $28.3 million ($336.1 million net unrealized loss and a $307.8 million net gain for cash received on settled contracts). In the nine months ended September 30, 2011, we recorded a net derivative gain of $232.0 million ($50.6 million net unrealized gain and a $181.4 million net gain for cash received on settled contracts).
Interest expense and other increased $39.6 million for the nine months ended September 30, 2012 compared to the same period in 2011. The increase is primarily the result of our accounting for the KinderHawk and EagleHawk joint ventures under the financing method for a failed sale of in substance real estate. For the nine months ended September 30, 2012, we recorded approximately $121.3 million of interest expense on the financing obligations compared to the prior year period of $80.5 million.
We had an income tax benefit of $77.1 million for the nine months ended September 30, 2012 due to our loss from continuing operations before income taxes of $211.5 million compared to an income tax provision of $73.6 million for the nine months ended September 30, 2011 due to our income from continuing operations before income taxes of $201.3 million. The effective tax rate for the nine months ended September 30, 2012 and 2011 was 36.4% and 36.6%, respectively. The decrease in our effective tax rate is due to the shift in the Company’s capital spending to Texas from Louisiana which has historically had a higher tax rate than Texas. Also contributing to the decrease was the true-up of prior year income taxes due to the non-deductibility of certain success-based merger fees.
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Investment in EagleHawk
EagleHawk had gross revenues of $67.8 million related to its Eagle Ford Shale gathering and treating systems in the Hawkville and Black Hawk Fields for the nine months ended September 30, 2012 compared to gross revenue of $10.1 million in the same period in 2011. Gross revenues of $67.8 million and $10.1 million included $28.2 million and $6.2 million, respectively, of intercompany revenues that were eliminated in consolidation. The increase of $57.7 million is due to the formation of EagleHawk on July 1, 2011 and as a result, the higher amount of volumes in the nine months ended September 30, 2012 as compared to three months in 2011.
Total operating expenses for EagleHawk for the nine months ended September 30, 2012 and 2011 of $34.4 million and $6.0 million, respectively, included $17.7 million and $3.3 million in gathering, transportation and other expenses and $12.2 million and $2.0 million in depreciation expense. Gathering, transportation and other expenses for EagleHawk consist of costs to operate the pipelines, such as treating, processing, measuring and transporting expenses. Depreciation expense on EagleHawk’s gathering and treating systems is calculated based on a 30 year useful life commencing on the estimated placed in service date. The increases in gathering, transportation and other expenses and in depreciation expense is due to the formation of EagleHawk on July 1, 2011 and as a result, the higher amount of volumes in the nine months ended September 30, 2012 as compared to three months in 2011. 32