BHP Group Limited (BHP) 6-K BHP - Petrohawk March 2013 Financial Report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 6-K

REPORT OF FOREIGN PRIVATE ISSUER

PURSUANT TO RULE 13a-16 OR 15d-16

UNDER THE SECURITIES EXCHANGE ACT OF 1934

May 8, 2013

BHP BILLITON LIMITED (ABN 49 004 028 077)	BHP BILLITON PLC (REG. NO. 3196209)
(Exact name of Registrant as specified in its charter)	(Exact name of Registrant as specified in its charter)

VICTORIA, AUSTRALIA	ENGLAND AND WALES
(Jurisdiction of incorporation or organisation)	(Jurisdiction of incorporation or organisation)
180 LONSDALE STREET, MELBOURNE, VICTORIA 3000 AUSTRALIA	NEATHOUSE PLACE, VICTORIA, LONDON, UNITED KINGDOM
(Address of principal executive offices)	(Address of principal executive offices)

Indicate by check mark whether the registrant files or will file annual reports under cover of Form 20-F or Form 40-F:     x  Form 20-F    ¨  Form 40-F

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1):  ¨

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(7):  ¨

Indicate by check mark whether the registrant by furnishing the information contained in this Form is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934:    ¨  Yes    x  No

If “Yes” is marked, indicate below the file number assigned to the registrant in connection with Rule 12g3-2(b): n/a

The accompanying Quarterly Report to Security Holders (the “Petrohawk Quarterly Report” or the “Report”) was provided to holders of Petrohawk Energy Corporation’s (“Petrohawk”) outstanding senior notes in accordance with the reporting covenants under the applicable indentures. The unaudited condensed consolidated financial statements in the Report have been prepared in accordance with accounting principles generally accepted in the United States. Petrohawk’s parent, BHP Billiton Limited, prepares its consolidated financial statements in accordance with International Financial Reporting Standards (“IFRS”). Petrohawk 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 Petrohawk’s historical accounting activities and do not reflect the acquisition of Petrohawk 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 the Petrohawk Quarterly Report are not indicative of the contribution of Petrohawk to the potential results of BHP Billiton Limited.

        

8 May 2013 BHP Billiton Limited 180 Lonsdale Street Melbourne Victoria 3000 Australia GPO BOX 86 Melbourne Victoria 3001 Australia Tel +61 1300 55 47 57 Fax +61 3 9609 4372 bhpbilliton.com BHP Billiton Plc
Neathouse Place London SW1V 1BH UK Tel +44 20 7802 4000 Fax + 44 20 7802 4111 bhpbilliton.com

To:	Australian Securities Exchange1	cc:	New York Stock Exchange
	London Stock Exchange		JSE Limited

PETROHAWK MARCH 2013 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 March 2013 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

¹  This release was made outside the hours of operation of the ASX market announcements office.

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

MARCH 31, 2013

1

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 condensed 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 allocations that were performed in conjunction with the business combination accounting performed by BHP Billiton Limited. Although the Company is wholly owned by BHP Billiton Limited, the Company has not established a new basis of accounting as such push down accounting from BHP Billiton Limited was deemed inappropriate for the accompanying condensed consolidated financial statements due to the nature of Petrohawk’s agreement with the bondholders. 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.

Notice of Change in Fiscal Year

On February 19, 2013, the Directors adopted a resolution authorizing a change in the Company’s fiscal year from a calendar year to a July 1 through June 30 fiscal year, to align with BHP Billiton Limited’s fiscal year. The Company’s transitional financial report to Security Holders will cover the period from January 1, 2013 through June 30, 2013, and will include all information otherwise required in an annual report to bondholders under section 4.2 of the Indentures.

2

PETROHAWK ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(In thousands)

	Three Months Ended March 31,
	2013			2012
Operating revenues:
Oil and natural gas	$	618,498		$	500,205
Marketing		51,902			(67	)
Midstream		18,502			18,756
Total operating revenues		688,902			518,894
Operating expenses:
Marketing		51,682			—
Production:
Lease operating		34,906			21,963
Workover and other		4,785			5,461
Taxes other than income		37,986			23,445
Gathering, transportation and other		87,604			79,842
General and administrative		51,742			45,704
Depletion, depreciation and amortization		279,148			294,459
Impairment of capitalized software costs		—			1,351
Total operating expenses		547,853			472,225
Income (loss) from operations		141,049			46,669
Other income (expenses):
Net gain (loss) on derivative contracts		—			(28,260	)
Interest expense and other		(107,177	)		(107,115	)
Total other income (expenses)		(107,177	)		(135,375	)
Income (loss) from continuing operations before income taxes		33,872			(88,706	)
Income tax benefit (provision)		(12,860	)		33,353
Net income (loss)	$	21,012		$	(55,353	)

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

3

PETROHAWK ENERGY CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)

(In thousands, except share and per share amounts)

	March 31, 2013			December 31, 2012
Current assets:
Cash	$	216,836		$	96,122
Accounts receivable		592,134			584,442
Deferred income tax		11,337			16,046
Prepaid and other		25,375			29,798
Total current assets		845,682			726,408
Oil and natural gas properties (full cost method):
Evaluated		13,805,661			13,213,484
Unevaluated		3,123,721			2,839,950
Gross oil and natural gas properties		16,929,382			16,053,434
Less – accumulated depletion		(6,967,104	)		(6,708,875	)
Net oil and natural gas properties		9,962,278			9,344,559
Other operating property and equipment:
Gas gathering systems and equipment		1,496,271			1,348,822
Other operating assets		131,331			130,026
Gross other operating property and equipment		1,627,602			1,478,848
Less – accumulated depreciation		(147,506	)		(126,366	)
Net other operating property and equipment		1,480,096			1,352,482
Other noncurrent assets:
Goodwill		932,802			932,802
Debt issuance costs, net of amortization		33,777			36,090
Deferred income taxes		344,933			352,446
Restricted cash		28,879			27,647
Other		19,331			14,792
Total assets	$	13,647,778		$	12,787,226
Current liabilities:
Accounts payable and accrued liabilities	$	1,147,934		$	1,166,106
Payable to financing arrangements		20,028			19,467
Current portion of long-term debt		—			—
Total current liabilities		1,167,962			1,185,573
Long-term debt		3,204,209			3,201,761
Other noncurrent liabilities:
Asset retirement obligations		57,835			57,236
Payable on financing arrangements		1,862,679			1,853,343
Other		427			417
Commitments and contingencies (Note 7)
Stockholders’ equity:
Common stock: 100 shares of $.001 par value authorized, issued and outstanding at March 31, 2013 and December 31, 2012		—			—
Additional paid-in capital		8,520,310			7,675,552
Accumulated deficit		(1,165,644	)		(1,186,656	)
Total stockholders’ equity		7,354,666			6,488,896
Total liabilities and stockholders’ equity	$	13,647,778		$	12,787,226

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

4

PETROHAWK ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (Unaudited)

(In thousands)

	Common				Additional Paid-in		Accumulated			Total Stockholders’
	Shares		Amount		Capital		Deficit			Equity
Balance at December 31, 2012		—	$	—	$	7,675,552	$	(1,186,656	)	$	6,488,896
Contribution from parent(1)		—		—		844,758		—			844,758
Net income		—		—		—		21,012			21,012
Balance at March 31, 2013		—	$	—	$	8,520,310	$	(1,165,644	)	$	7,354,666

(1) Includes both cash funding and non-cash contributions from BHP Billiton Limited. The cash funding for the three months ended March 31, 2013, totals approximately $0.8 billion, and the remainder is attributable to non-cash contributions, which are items paid by BHP Billiton Limited on behalf of Petrohawk.

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

5

PETROHAWK ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(In thousands)

	Three Months Ended March 31,
	2013			2012
Cash flows from operating activities:
Net income (loss)	$	21,012		$	(55,353	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation and amortization		279,148			294,459
Impairment of capitalized software costs		—			1,351
Income tax provision (benefit)		12,860			(33,353	)
Net unrealized (gain) loss on derivative contracts		—			336,058
Other operating		7,128			10,821
Change in assets and liabilities:
Accounts receivable		(7,691	)		(47,775	)
Prepaid and other		5,242			11,889
Accounts payable and accrued liabilities		142,391			4,497
Other		(5,178	)		748
Net cash provided by operating activities		454,912			523,342
Cash flows from investing activities:
Oil and natural gas capital expenditures		(996,557	)		(656,146	)
Increase in restricted cash		(82,640	)		(33,239	)
Decrease in restricted cash		81,408			9,941
Other operating property and equipment capital expenditures		(113,949	)		(104,727	)
Net cash used in investing activities		(1,111,738	)		(784,171	)
Cash flows from financing activities:
Contribution from parent		770,000			247,000
Repayment of borrowings		—			(17,520	)
Increase in payable on financing arrangements		16,250			26,910
Decrease in payable on financing arrangements		(8,710	)		(7,627	)
Net cash provided by financing activities		777,540			248,763
Net increase (decrease) in cash		120,714			(12,066	)
Cash at beginning of period		96,122			174,436
Cash at end of period	$	216,836		$	162,370

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

6

PETROHAWK ENERGY CORPORATION

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

1. FINANCIAL STATEMENT PRESENTATION

Basis of Presentation and Principles of Consolidation

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 Petrohawk through the merger of a wholly owned subsidiary of BHP Billiton Petroleum (North America) Inc., a Delaware corporation (which is a wholly owned subsidiary of BHP Billiton Limited), with and into Petrohawk, 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 between Petrohawk and its controlled subsidiaries have been eliminated. 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 Annual Report. Please refer to the Notes to the Consolidated Financial Statements in the Annual Report to Security Holders dated December 31, 2012, when reviewing interim financial results.

Subsequent events or transactions have been evaluated through the date of issuance of this report in conjunction with the preparation of these unaudited condensed consolidated financial statements, and the Company has included those subsequent events within the following notes where applicable.

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 Petrohawk, with Petrohawk continuing as the surviving corporation in the merger and as a wholly owned subsidiary of Parent (the BHP Merger). Although the Company is a wholly owned subsidiary of BHP Billiton Limited, the Company has not established a new basis of accounting as such push down accounting from BHP Billiton Limited was deemed inappropriate for the Company’s condensed consolidated financial statements due to the nature of Petrohawk’s agreement with the bondholders. Thus, the 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 allocations that were performed in conjunction with the business combination accounting performed by BHP Billiton Limited.

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.

7

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.

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 equipment for the three months ended March 31, 2013, and March 31, 2012.

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 were 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.

Gas gathering systems and equipment as of March 31, 2013 and December 31, 2012 consisted of the following:

	March 31,			December 31,
	2013			2012
	(In thousands)
Gas gathering systems and equipment	$	1,496,271		$	1,348,822
Less – accumulated depreciation		(77,280	)		(66,461	)
Net gas gathering systems and equipment	$	1,418,991		$	1,282,361

(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 March 31, 2013 and December 31, 2012, the table above includes approximately $401.7 million and $405.4 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 March 31, 2013 and December 31, 2012, the table above includes approximately $789.6 million and $715.3 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 lesser of lease term; rental equipment and capitalized software implementation costs, seven years; and computers, three years. 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.

8

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 Arrangements

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. 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 arrangements,” 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. 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. 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 arrangements,” 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 March 31, 2013 and December 31, 2012, was approximately $1.9 billion and $1.9 billion, respectively, of which approximately $20.0 million and $19.5 million was classified as current for the respective periods.

Restricted Cash

In conjunction with the termination of the EagleHawk Revolving Credit Agreement during 2011, EagleHawk began issuing cash calls in accordance with each party’s membership interest to the Company and Kinder Morgan in order to fund EagleHawk’s capital expenditures needs. Since EagleHawk’s cash balances are restricted for the purpose of funding its capital program, the Company presented EagleHawk’s cash of approximately $24.4 million and $23.5 million as“Restricted cash” at March 31, 2013 and December 31, 2012, respectively. Additionally, from time to time, the Company may be requested to escrow certain disputed royalty funds, and as a result, the Company presented cash of approximately $4.5 million and $4.1 million as“Restricted Cash”at March 31, 2013 and December 31, 2012, respectively.

9

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 does 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 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.”

Goodwill

Goodwill represents the excess of the purchase price over the estimated fair value of the 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 an event occurs or circumstances change that could potentially result in impairment. The goodwill impairment test requires the allocation of goodwill and all other assets and liabilities to reporting units.

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 Goodwill for 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 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 under the straight-line method over the life of the contract. Any unamortized balance of the Company’s intangible assets will be subject to impairment testing pursuant to theImpairment 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.

There was no amortization expense during the three months ended March 31, 2013. Amortization expense was $2.8 million for the three months ended March 31, 2012, and was included in“Gathering, transportation and other” on the unaudited condensed consolidated statements of operations.

During 2012, one acquired transportation contract (the Kaiser contract) for gas export from the Haynesville field reached a point at which the Company has the option to cancel or extend the contract at its sole discretion. Due to the changes in the gas market since the time of acquisition and the availability of alternative transportation routes, the decision was made not to extend this contract. As a result, a change in circumstances was noted and the remaining net book value of approximately $67.2 million associated with the Kaiser contract was impaired.

Intangible assets subject to amortization at March 31, 2013 and December 31, 2012, are as follows:

	March 31,		December 31,
	2013		2012
	(In thousands)
Transportation contracts	$	—	$	105,108
Less – accumulated amortization		—		(37,871	)
Less – impairment of Kaiser contract		—		(67,237	)
Net transportation contracts	$	—	$	—

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Recently Issued Accounting Pronouncements

In July 2012, the FASB issued ASU 2012-02,Intangibles-Goodwill and Other (Topic 350): Testing Indefinite-Lived Intangible Assets for Impairment (ASU 2012-02). This guidance is intended to simplify the impairment test for indefinite-lived intangible assets other than goodwill by giving entities the option to first assess qualitative factors to determine whether it is more likely than not that an indefinite-lived intangible asset is impaired. The results of the qualitative assessment would be used as a basis in determining whether it is necessary to perform the two-step quantitative impairment testing. An entity can choose to perform the qualitative assessment on none, some or all of its indefinite-lived intangible assets, or may bypass the qualitative assessment and proceed directly to the quantitative impairment test. This guidance will be effective for annual and interim impairment tests performed for fiscal years beginning after September 15, 2012, with early adoption permitted in certain circumstances. As the Company does not currently have any indefinite-lived intangible assets, this guidance will have no impact on its operating results, financial position, cash flows and disclosures.

In February 2013, the FASB issued ASU 2013-04,Liabilities (Topic 405): Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation Is Fixed at the Reporting Date (ASU 2013-04). This guidance is intended to provide guidance for the recognition, measurement, and disclosure of obligations resulting from joint and several liability arrangements for which the total amount of the obligation is fixed at the reporting date, excluding obligations accounted for under existing guidance. This guidance requires an entity to measure these obligations as a sum of the amount the reporting entity agreed to pay and any additional amount the reporting entity expects to pay on behalf of its co-obligors. This guidance will be effective for fiscal years ending after December 15, 2014, and interim and annual periods thereafter, with early adoption permitted. The Company is currently assessing the impact, if any, that ASU 2013-04 will have on its disclosures.

2. 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. 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.

The Company assesses all items classified as unevaluated property on a periodic 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 and the full cost ceiling test limitation.

At March 31, 2013, the ceiling test value of the Company’s reserves was calculated based on the first day average of the 12-months ended March 31, 2013, of the West Texas Intermediate (WTI) spot price of $92.81 per barrel or was calculated based equally on the respective first day average of the 12-months ended March 31, 2013, of the WTI spot price of $92.81 per barrel and the Light Louisiana Sweet (LLS) differential spot price of $18.41 per barrel, depending on location and adjusted by lease or field for quality, transportation fees, and regional price differentials, and the first day average of the 12-months ended March 31, 2013 of the Henry Hub price of $2.97 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 March 31, 2013 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 March 31, 2012 the ceiling test value of the Company’s reserves was calculated based on the first day average of the 12-months ended March 31, 2012, of the WTI spot price of $98.15 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 March 31, 2012 of the Henry Hub price of $3.73 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 March 31, 2012 did not exceed the ceiling amount.

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3. LONG-TERM DEBT

Long-term debt as of March 31, 2013 and December 31, 2012, consisted of the following:

	March 31, 2013		December 31, 2012
	(In thousands)
6.25% $600 million senior notes	$	600,000	$	600,000
7.25% $1.2 billion senior notes(1)		1,230,723		1,230,942
10.5% $600 million senior notes(2)		573,875		571,208
7.875% $800 million senior notes		799,611		799,611
	$	3,204,209	$	3,201,761

(1) Amount includes a $5.7 million and $5.9 million premium at March 31, 2013 and December 31, 2012, respectively, 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.

(2) Amount includes a $15.8 million and $18.4 million discount, at March 31, 2013 and December 31, 2012, respectively, which was recorded by the Company in conjunction with the issuance of the 10.5% senior notes due 2014. 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 revolving credit facility 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 10,“EagleHawk Field Services.” Petrohawk Energy Corporation, the issuer of the 2019 Notes, has no material independent assets or operations apart from the assets and operations of its subsidiaries.

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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 10,“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 $5.7 million and $5.9 million at March 31, 2013 and December 31, 2012, respectively.

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 August 1, 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).

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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, commencing August 1, 2009. 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 10,“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 $15.8 million and $18.4 million at March 31, 2013 and December 31, 2012, respectively.

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) pursuant to an indenture (the 2015 Indenture). 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 Notes bear interest at a rate of 7.875% per annum, payable semi-annually on June 1 and December 1 of each year, commencing December 1, 2008. 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 10,“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 March 31, 2013 and December 31, 2012, the Company had approximately $33.8 million and $36.1 million, respectively, of debt issuance costs remaining that are being amortized over the lives of the respective debt.

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4. FAIR VALUE MEASUREMENTS

Pursuant to ASC 820,Fair Value Measurements and Disclosures (ASC 820) the Company’s determination of fair value incorporated 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 utilized 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 classified fair value balances based on the observability of those inputs.

There were no financial assets or liabilities that were accounted for at fair value as of March 31, 2013 or December 31, 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 7,“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 year ended December 31, 2012.

Derivatives terminated during the first quarter of 2012 include collars, swaps, and put options that are carried at fair value. The Company recorded the net change in the fair value of these positions in“Net gain on derivative contracts” in the Company’s unaudited condensed consolidated statements of operations. The Company was 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.

Historically, 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 was exposed to credit risk to the extent of nonperformance by the counterparties in the derivative contracts discussed above. 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.

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 following table presents the estimated fair values of the Company’s fixed interest rate, long-term debt instruments as of March 31, 2013 and December 31, 2012 (excluding premiums and discounts and deferred premiums on derivative contracts):

	March 31, 2013				December 31, 2012
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
	(In thousands)
Debt
6.25% $600 million senior notes	$	600,000	$	681,462	$	600,000	$	684,600
7.25% $1.2 billion senior notes		1,225,000		1,365,263		1,225,000		1,375,063
10.5% $600 million senior notes		589,640		636,000		589,640		635,250
7.875% $800 million senior notes		799,611		808,504		799,611		832,800
	$	3,214,251	$	3,491,229	$	3,214,251	$	3,527,713

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 March 31, 2013 and December 31, 2012, respectively.

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5. ASSET RETIREMENT OBLIGATION

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 a portion of 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 the ARO liability for the three months ended March 31, 2013 (in thousands):

Liability for asset retirement obligation as of December 31, 2012	$	57,236
Additions		—
Accretion expense		599
Revisions in estimated cash flows and other		—
Liability for asset retirement obligation as of March 31, 2013	$	57,835

6. 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 $7.2 million and $2.4 million for the three months ended March 31, 2013 and 2012, respectively.

As of March 31, 2013, the Company had the following commitments:

	Total Obligation Amount		Years Remaining
	(in thousands)
Gathering and transportation commitments	$	3,179,012		16
Drilling rig commitments		786,602		6
Non-cancelable operating leases		7,896		1
Pipeline and well equipment obligations		148,370		1
Various contractual commitments (including, among other things, rental equipment obligations, obtaining and processing seismic data)		66,460		1
Total commitments	$	4,188,340

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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. In addition, the Company pays an annual 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:

Contract Year	Minimum Annual 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.

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 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 fee would be $34.3 million.

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 March 31, 2013 and December 31, 2012, was approximately $1.9 billion and $1.9 billion, respectively, of which approximately $20.0 million and $19.5 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 probable 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’s consolidated operating results, financial position or cash flows.

7. 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 condensed consolidated balance sheets, with the changes in the fair value included in the condensed consolidated statements of operations for the period in which the change occurs.

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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 March 31, 2013 and December 31, 2012, the Company had no open commodity derivative contracts.

Additionally, the Company had deferred premiums on derivative contracts outstanding in the amount of approximately $17.5 million, which were settled during the first quarter of 2012.

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 for the three months ended March 31, 2012:

Derivative not designated as hedging contracts under ASC 815	Location of gain or (loss) recognized in income on derivative contracts	Amount of gain or  (loss) in income on derivative contracts For the three months ended March 31, 2012
		(in thousands)
Commodity contracts:
Unrealized loss on commodity contracts	Other income (expense) – net loss on derivative contracts	$	(336,058	)
Realized gain on commodity contracts	Other income (expense) – net loss on derivative contracts		307,798
Total net loss on commodity contracts		$	(28,260	)

8. STOCKHOLDERS’ 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 is authorized to issue 100 shares with par value of $0.001 per share all of which are owned by Parent.

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9. ADDITIONAL FINANCIAL STATEMENT INFORMATION

Certain balance sheet amounts are comprised of the following:

	March 31, 2013		December 31, 2012
	(In thousands)
Accounts receivable:
Oil and natural gas revenues	$	254,580	$	196,220
Joint interest accounts		277,887		333,390
Income and other taxes receivable		11,592		19,008
Other		48,075		35,824
	$	592,134	$	584,442
Prepaids and other:
Prepaid insurance	$	285	$	3,320
Prepaid drilling costs		21,595		23,349
Other		3,495		3,129
	$	25,375	$	29,798
Accounts payable and accrued liabilities:
Trade payables	$	94,625	$	48,322
Revenues and royalties payable		284,479		220,737
Accrued oil and natural gas capital costs		429,641		559,714
Accrued midstream capital costs		80,249		45,445
Accrued interest expense		55,824		68,312
Prepayment liabilities		47,893		57,762
Accrued lease operating expenses		20,735		15,035
Accrued ad valorem taxes payable		24,029		19,574
Accrued production taxes payable		8,747		9,220
Accrued gathering, transportation and other expenses		57,154		50,712
Accrued employee compensation		7,689		18,880
Income taxes payable		23,806		23,806
Other		13,063		28,587
	$	1,147,934	$	1,166,106

10. EAGLEHAWK FIELD SERVICES

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. We have 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 months ended March 31, 2013 and 2012:

	Three Months Ended March 31, 2013			Three Months Ended March 31, 2012
Operating revenues:
Midstream	$	10,286		$	11,883
Total operating revenues		10,286			11,883
Operating expenses:
Taxes other than income		1,294			935
Gathering, transportation and other		15,261			5,822
General and administrative		507			491
Depletion, depreciation and amortization		5,934			3,471
Total operating expenses		22,996			10,719
Gain (Loss) from operations		(12,710	)		1,164
Other income (expenses):
Interest expense and other		(2,357	)		(3,349	)
Total other income (expenses)		(2,357	)		(3,349	)
Loss from continuing operations before income taxes		(15,067	)		(2,185	)
Income tax benefit		5,721			822
Net gain (loss)	$	(9,346	)	$	(1,363	)

The following table presents balance sheet information for EagleHawk as of March 31, 2013 and December 31, 2012:

	March 31, 2013			December 31, 2012
Current assets:
Cash	$	24,367		$	23,508
Accounts receivable		31,980			28,623
Prepaids and other		7			61
Total current assets		56,354			52,192
Other operating property and equipment:
Gas gathering systems and equipment		822,591			742,333
Other operating assets		1,026			1,026
Gross other operating property and equipment		823,617			743,359
Less—accumulated depreciation		(33,408	)		(27,477	)
Net other operating property and equipment		790,209			715,882
Other noncurrent assets:
Deferred income taxes		5,721			3,514
Total assets	$	852,284		$	771,588
Current liabilities:
Accounts payable and accrued liabilities	$	76,621		$	49,950
Total current liabilities		76,621			49,950
Long-term debt		—			—
Other noncurrent liabilities
Payable to affiliate		247,467			236,197
Asset retirement obligations		13,009			13,009
Other		6			7
Stockholders’ equity:
Additional paid-in capital		522,184			484,715
Accumulated deficit		(7,003	)		(12,290	)
Total stockholders’ equity		515,181			472,425
Total liabilities and stockholders’ equity	$	852,284		$	771,588

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The following table presents cash flow statement information for EagleHawk for the three months ended March 31, 2013 and 2012:

	Three Months Ended March 31,
	2013			2012
Cash flows from operating activities:
Net loss	$	(9,346	)	$	(1,363	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depletion, depreciation and amortization		5,934			3,471
Income tax provision (benefit)		(5,721	)		(822	)
Other operating		1			45
Change in assets and liabilities:
Accounts receivable		(5,620	)		(5,617	)
Prepaid and other		50			(153	)
Accounts payable and accrued liabilities		1,163			3,010
Net cash used in operating activities		(13,539	)		(1,429	)
Cash flows from investing activities:
Other operating property and equipment capital expenditures		(52,483	)		(82,628	)
Net cash used in investing activities		(52,483	)		(82,628	)
Cash flows from financing activities:
Proceeds from borrowings		—			—
Repayment of borrowings		—			—
Debt issuance costs		—			—
Payable to affiliate		29,411			36,047
Contributions from affiliate		48,750			80,730
Distributions to affiliate		(11,280	)		(9,422	)
Net cash provided by financing activities		66,881			107,355
Net increase (decrease) in cash		859			23,298
Cash at beginning of period		23,508			34,736
Cash at end of period	$	24,367		$	58,034

As discussed in Note 3,“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.

MANAGEMENT’S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS

The following discussion is intended to assist in understanding our results of operations for the three months ended March 31, 2013 and 2012 and should be read in conjunction with our unaudited condensed consolidated financial statements and the accompanying notes included in this report and with the consolidated financial statements, notes, and management’s narrative analysis included in our Annual Report to Security Holders dated December 31, 2012.

Statements in this discussion 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.

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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 are from internally generated cash flows from operations and funding from our Parent or otherwise arranged with third party lenders in accordance with the indentures governing our four outstanding series of senior notes.

Contractual Obligations

We believe we have a significant degree of flexibility to adjust the level of our future capital expenditures as circumstances warrant. Our level of capital expenditures will vary in future periods depending on the success we experience in our acquisition, developmental 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 March 31, 2013.

	Total Obligation Amount		Years Remaining
	(in thousands)
Gathering and transportation commitments	$	3,179,012		16
Drilling rig commitments		786,602		6
Non-cancelable operating leases		7,896		1
Pipeline and well equipment obligations		148,370		1
Various contractual commitments (including, among other things, rental equipment obligations, obtaining and processing seismic data)		66,460		1
Total commitments	$	4,188,340

For more information on amounts not included in the table above, refer to Note 6, “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. The preparation of our unaudited condensed consolidated financial statements requires us to make estimates and assumptions that affect our reported results of operations and the amount of reported assets and liabilities. There have been no material changes to our critical accounting policies from those described in our Annual Report to Security Holders dated December 31, 2012.

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Comparison of Results of Operations

Three Months Ended March 31, 2013 Compared to Three Months Ended March 31, 2012

We reported income from continuing operations, net of income taxes, of $21.0 million for the three months ended March 31, 2013, compared to a loss from continuing operations, net of income taxes, of $55.4 million for the comparable period in 2012. The following table summarizes key items of comparison and their related change for the periods indicated.

	Three Months Ended March 31,
(In thousands (except per unit and per Mcfe amounts))	2013			2012			Change
Income (loss) from continuing operations, net of income taxes	$	21,012		$	(55,353	)	$	76,365
Operating revenues:
Oil and natural gas		618,498			500,205			118,293
Marketing		51,902			(67	)		51,969
Midstream		18,502			18,756			(254	)
Operating expenses:
Marketing		51,682			—			51,682
Production:
Lease operating		34,906			21,963			12,943
Workover and other		4,785			5,461			(676	)
Taxes other than income		37,986			23,445			14,541
Gathering, transportation and other		87,604			79,842			7,762
General and administrative		51,742			45,704			6,038
Depletion, depreciation and amortization:
Depletion – Full cost		258,229			282,829			(24,600	)
Depreciation – Midstream		10,820			7,132			3,688
Depreciation – Other		9,500			3,800			5,700
Accretion expense		599			698			(99	)
Impairment of capitalized software costs		—			1,351			(1,351	)
Other income (expenses):
Net gain on derivative contracts		—			(28,260	)		28,260
Interest expense and other		(107,177	)		(107,115	)		(62	)
Income from continuing operations before income taxes		33,872			(88,706	)		122,578
Income tax benefit (provision)		(12,860	)		33,353			(46,213	)
Production:
Natural gas – Mmcf		79,803			88,075			(8,272	)
Crude oil – MBbl		2,997			2,204			793
Natural gas liquids – MBbl		1,881			1,242			639
Natural gas equivalent – Mmcfe(1)		109,074			108,751			323
Average daily production – Mmcfe(1)		1,212			1,195			17
Average price per unit(2):
Natural gas price – Mcf	$	3.26		$	2.49			0.77
Crude oil price – Bbl		102.09			101.86			0.23
Natural gas liquids price – Bbl		28.29			42.35			(14.06	)
Natural gas equivalent price – Mcfe(1)		5.68			4.57			1.11
Average cost per Mcfe:
Production:
Lease operating		0.32			0.20			0.12
Workover and other		0.04			0.05			(0.01	)
Taxes other than income		0.35			0.22			0.13
Gathering, transportation and other		0.80			0.73			0.07
General and administrative		0.47			0.42			0.05
Depletion		2.37			2.60			(0.23	)

(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.

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For the three months ended March 31, 2013, oil and natural gas revenues increased $118.3 million from the same period in 2012, to $618.5 million. The increase was primarily due to the increase in our realized average price of $1.11 per Mcfe to $5.68 per Mcfe from $4.57 per Mcfe in the prior year period. The increase per Mcfe led to an increase in oil and natural gas revenues of approximately $120.8 million for the three months ended March 31, 2013. The increase in oil and natural gas revenues was also partially due to the increase in our production of 323 Mmcfe over 2012, primarily due to increased drilling in the Eagle Ford Shale. Increased production contributed approximately $1.8 million in revenues for the three months ended March 31, 2013.

We had marketing revenues of $51.9 million and marketing expenses of $51.7 million for the three months ended March 31, 2013, resulting in income before income taxes of $0.2 million. Marketing revenues and expenses are related to the purchase and sale of third party condensate.

We had gross revenues from our midstream business of $37.3 million for the three months ended March 31, 2013, compared to the same period in 2012 of $29.9 million, an increase of $7.4 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, net of eliminations for intercompany amounts associated with gathering and treating services provided to us on the unaudited condensed consolidated statements of operations. For the three months ended March 31, 2013, approximately $10.3 million in revenues, after intercompany eliminations, from EagleHawk were reported in midstream revenues on the unaudited condensed consolidated statements of operations. Gross revenues of $37.3 million also included $18.8 million of intercompany revenues that were eliminated in consolidation. On a net basis, we had revenues of $18.5 million for the three months ended March 31, 2013, a decrease of $0.3 million from the prior year. This decrease is attributed to a decrease in the margin earned on third party volumes as a result of decreased trucking transportation.

Lease operating expenses increased $12.9 million for the three months ended March 31, 2013, as compared to the same period in 2012. The increase was primarily due to an increase in the number of wells, combined with increased production and an increase in the mix of liquids to gas volumes. On a per unit basis, lease operating expenses increased $0.12 per Mcfe to $0.32 per Mcfe in 2013 from $0.20 per Mcfe in 2012.

Taxes other than income increased $14.5 million for the three months ended March 31, 2013, as compared to the same period in 2012. The largest components of taxes other than income are production and severance taxes which are generally assessed as either a fixed rate based on production or as a percentage of gross oil and natural gas sales. Our increase in production in the current year was partially offset by severance tax refunds related to drilling incentives for horizontal wells in the Haynesville and Eagle Ford Shales. For the three months ended March 31, 2013, we recorded severance tax refunds totaling $3.5 million compared to $3.6 million in the prior year. On a per unit basis, excluding the severance tax refunds, taxes other than income were $0.38 per Mcfe in 2013 compared to $0.25 per Mcfe in 2012.

Gathering, transportation and other expense increased $7.8 million for the three months ended March 31, 2013 as compared to the same period in 2012. On a per unit basis, gathering transportation and other increased $0.07 per Mcfe from $0.73 per Mcfe in 2012 to $0.80 per Mcfe in 2013. The overall increase is due to higher cost per unit for liquids and an increase in liquids volumes, combined with deficiency payments associated with unutilized gathering and treating and firm transportation capacity.

General and administrative expense for the three months ended March 31, 2013, increased $6.0 million as compared to the same period in 2012. The increase is primarily attributable to an increase in the estimated provision for the Tulsa Office Closure of $4.5 million and an increase in the estimated provision for litigation of $2.0 million.

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 decreased $24.6 million for the three months ended March 31, 2013, from the same period in 2012, to $258.2 million. On a per unit basis, depletion expense decreased $0.23 per Mcfe to $2.37 per Mcfe. The decrease on a per unit basis is primarily due to an increase in our reserve volume partially offset by capital spending during the three months ended March 31, 2013.

Depreciation expense associated with our gas gathering systems increased $3.7 million to $10.8 million for the three months ended March 31, 2013, as compared to the same period in 2012. The increase was due to the growth in our midstream operations from capital spending. We depreciate our gas gathering systems over a 30 year useful life commencing on the estimated placed in service date.

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Depreciation expense associated with our other operating property and equipment increased $5.7 million to $9.5 million for the three months ended March 31, 2013, as compared to the same period in 2012. The increase is primarily due to expansion and the growth of our capital spending.

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.

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. During the three months ended March 31, 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).

Interest expense and other increased less than $0.1 million for the three months ended March 31, 2013, compared to the same period in 2012. The increase is primarily the result of our accounting for KinderHawk and the EagleHawk joint venture under the financing method for a failed sale of in substance real estate. For the three months ended March 31, 2013, we recorded approximately $39.7 million of interest expense on the financing obligations compared to $39.8 million in the prior year.

We had an income tax provision of $12.9 million for the three months ended March 31, 2013, due to our income from continuing operations before income taxes of $33.9 million compared to an income tax benefit of $33.4 million due to our loss from continuing operations before income taxes of $88.7 million in the prior year. The effective tax rate for the three months ended March 31, 2013, was 38.0% compared to 37.6% for the three months ended March 31, 2012.

Investment in EagleHawk

EagleHawk had gross revenues of $24.9 million related to its Eagle Ford Shale gathering and treating systems in the Hawkville and Black Hawk Fields for the three months ended March 31, 2013, compared to $20.8 million for the three months ended March 31, 2012. Gross revenues include $14.6 million and $8.9 million of intercompany revenues that were eliminated in consolidation for the three months ended March 31, 2013 and 2012, respectively. Total operating expenses for EagleHawk for the three months ended March 31, 2013, of $23.0 million included $15.3 million in gathering, transportation and other expenses and $5.9 million in depreciation expense. Total operating expenses for the three months ended March 31, 2012, of $10.7 million included $5.8 million in gathering, transportation and other expenses and $3.5 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.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	BHP Billiton Limited and BHP Billiton Plc
Date: May 8, 2013	By:	/s/ Jane McAloon
	Name:	Jane McAloon
	Title:	Group Company Secretary