Edgar Filing: BHP BILLITON LTD

BHP Billiton Limited and BHP Billiton Plc

Date: November 7, 2013

/s/ Jane McAloon

Jane McAloon

Group Company Secretary

Form 6-K

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

November 7, 2013

BHP BILLITON LIMITED

(ABN 49 004 028 077)

BHP BILLITON PLC

(REG. NO. 3196209)

(Exact name of Registrant as specified in its charter)


VICTORIA, AUSTRALIA		ENGLAND AND WALES
(Jurisdiction of incorporation or organisation)		(Jurisdiction of incorporation or organisation)

171 COLLINS STREET, MELBOURNE,

VICTORIA

3000 AUSTRALIA

NEATHOUSE PLACE, LONDON,

UNITED KINGDOM

(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 allocations 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.

LOGO


	BHP Billiton Limited	BHP Billiton Plc
	171 Collins Street	Neathouse Place
	Melbourne Victoria 3000 Australia	London SW1V 1BH UK
	GPO BOX 86	Tel +44 20 7802 4000
7 November 2013	Melbourne Victoria 3001 Australia	Fax + 44 20 7802 4111
7 November 2013	Tel +61 1300 55 47 57 Fax +61 3 9609 3015	bhpbilliton.com
	bhpbilliton.com


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

PETROHAWK SEPTEMBER 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 September 2013 financial report (Quarterly 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 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: 171 Collins Street, Melbourne, Victoria 3000		Registered Office: Neathouse Place, London SW1V 1BH United Kingdom

The BHP Billiton Group is headquartered in Australia

PETROHAWK ENERGY CORPORATION

QUARTERLY REPORT TO SECURITY HOLDERS

SEPTEMBER 30, 2013

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 covered the period from January 1, 2013 through June 30, 2013, and included all information otherwise required in an annual report to bondholders under section 4.2 of the Indentures. This was issued to security holders of record on September 26, 2013.

As a result of the fiscal year change, please note that this is the first quarter report for the fiscal year ending June 30, 2014.

PETROHAWK ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(In thousands)


	Three Months Ended Sept 30,
	2013			2012
Operating revenues:
Oil and natural gas	$	841,839		$	502,475
Marketing		98,351			5,329
Midstream		12,228			17,804

Total operating revenues		952,418			525,608

Operating expenses:
Marketing		97,925			4,976
Production:
Lease operating		53,567			22,777
Workover and other		7,459			4,409
Taxes other than income		41,801			17,191
Gathering, transportation and other		125,444			75,995
General and administrative		69,149			35,500
Depletion, depreciation and amortization		366,569			311,629
Rig contract termination costs		61,378			—
Accretion expense		1,980			599

Total operating expenses		825,272			473,076

Income (loss) from operations		127,146			52,532

Other income (expenses):
Interest expense and other		(107,743	)		(107,530	)

Total other income (expenses)		(107,743	)		(107,530	)

Income (loss) from continuing operations before income taxes		19,403			(54,998	)
Income tax benefit (expense)		(8,465	)		22,332

Net income (loss)	$	10,938		$	(32,666	)

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

PETROHAWK ENERGY CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)

(In thousands, except share and per share amounts)


	September 30, 2013			June 30, 2013
Current assets:
Cash	$	216,071		$	214,990
Accounts receivable		592,253			523,257
Deferred income tax		10,637			9,950
Prepaid and other		48,593			33,372

Total current assets		867,554			781,569

Oil and natural gas properties (full cost method):
Evaluated		16,592,590			15,329,505
Unevaluated		2,866,399			3,010,761

Gross oil and natural gas properties		19,458,989			18,340,266
Less – accumulated depletion		(7,641,344	)		(7,297,291	)

Net oil and natural gas properties		11,817,645			11,042,975

Other operating property and equipment:
Gas gathering systems and equipment		1,756,755			1,648,198
Other operating assets		130,188			138,027

Gross other operating property and equipment		1,886,943			1,786,225
Less – accumulated depreciation		(192,892	)		(168,367	)

Net other operating property and equipment		1,694,051			1,617,858

Other noncurrent assets:
Goodwill		932,802			932,802
Debt issuance costs, net of amortization		29,150			31,463
Deferred income taxes		342,355			351,506
Restricted cash		27,844			35,236
Other		13,936			13,676

Total assets	$	15,725,337		$	14,807,085


Current liabilities:
Accounts payable and accrued liabilities	$	1,287,066		$	1,558,815
Payable to financing arrangements		22,094			20,894
Current debt		579,522			—

Total current liabilities		1,888,682			1,579,709

Long-term debt		2,629,886			3,206,766
Other noncurrent liabilities:
Asset retirement obligations		164,628			156,083
Payable on financing arrangements		1,890,450			1,871,584
Other		414			415
Commitments and contingencies (Note 6)
Stockholders’ equity:
Common stock: 100 shares of $.001 par value authorized, issued and outstanding at September 30, 2013 and June 30, 2013		—			—
Additional paid-in capital		10,322,019			9,174,208
Accumulated deficit		(1,170,742	)		(1,181,680	)

Total stockholders’ equity		9,151,277			7,992,528

Total liabilities and stockholders’ equity	$	15,725,337		$	14,807,085

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

PETROHAWK ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (Unaudited)

(In thousands)


					Additional					Total
	Common				Paid-in		Accumulated			Stockholders’
	Shares		Amount		Capital		Deficit			Equity
Balance at June 30, 2013		—	$	—	$	9,174,208	$	(1,181,680	)	$	7,992,528
Contribution from parent ⁽¹⁾		—		—		1,147,811		—			1,147,811
Net income		—		—		—		10,938			10,938

Balance at September 30, 2013		—	$	—	$	10,322,019	$	(1,170,742	)	$	9,151,277

(1)	Includes both cash funding and non-cash contributions from BHP Billiton Limited. The cash funding for the three months ended September 30, 2013, totals approximately $1.1 billion.

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

PETROHAWK ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(In thousands)


	Three Months Ended September 30,
	2013			2012
Cash flows from operating activities:
Net income (loss)	$	10,938		$	(32,666	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation and amortization		366,569			311,629
Accretion expense		1,980			599
Income tax expense (benefit)		8,464			(22,332	)
Other operating		13,874			12,036
Change in assets and liabilities:
Accounts receivable		(68,997	)		(59,267	)
Prepaid and other		(13,131	)		(1,710	)
Accounts payable and accrued liabilities		(56,284	)		(87,359	)
Other		(342	)		(4,932	)

Net cash provided by operating activities		263,071			115,998


Cash flows from investing activities:
Oil and natural gas capital expenditures		(1,293,460	)		(824,315	)
Increase in restricted cash		(148,571	)		(23,498	)
Decrease in restricted cash		155,963			45,983
Other operating property and equipment capital expenditures		(135,073	)		(138,986	)
Other		2			—

Net cash used in investing activities		(1,421,139	)		(940,816	)


Cash flows from financing activities:
Contribution from parent		1,148,000			903,806
Repayment of borrowings		—			—
Increase in payable on financing arrangements		22,474			10,296
Decrease in payable on financing arrangements		(11,328	)		(8,309	)
Other		3			—

Net cash provided by financing activities		1,159,149			905,793


Net increase (decrease) in cash		1,081			80,975

Cash at beginning of period		214,990			112,898

Cash at end of period	$	216,071		$	193,873

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

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 predominantly oil and gas shale 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 Transition Report to Security Holders dated June 30, 2013, 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.

Change of Fiscal Year – Changes to Comparative Periods

Following these changes in our reporting period, the period July 1, 2013 to June 30, 2014 is referred to as the 2014 fiscal year. The period January 1, 2013 to June 30, 2013 is referred to as the 2013 fiscal year. January 1, 2012 to December 31, 2012 is referred to as the 2012 fiscal year. As a result of the fiscal year change, please note that this is the first quarter report for the fiscal year ending June 30, 2014.

Use of Estimates

The preparation of the Company’s unaudited condensed consolidated financial statements in conformity with accounting principles generally accepted in the United States requires the Company’s management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the unaudited condensed consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods. The Company bases its estimates and judgments on historical experience and on various other assumptions and information that are believed to be reasonable under the circumstances. Estimates and assumptions about future events and their effects cannot be perceived with certainty and, accordingly, these estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as the Company’s operating environment changes. Actual results may differ from the estimates and assumptions used in the preparation of the Company’s unaudited condensed consolidated financial statements.

Interim period results are not necessarily indicative of results of operations or cash flows for the full year and accordingly, certain information normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States has been condensed or omitted.

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 September 30, 2013 or for the three months ended September 30, 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 BHP Billiton Petroleum (Eagle Ford Gathering) LLC, formerly known as Eagle Hawk 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 September 30, 2013 and June 30, 2013 consisted of the following:


	September 30, 2013			June 30, 2013
	(In thousands)
Gas gathering systems and equipment	$	1,756,755		$	1,648,198
Less – accumulated depreciation		(101,559	)		(88,714	)

Net gas gathering systems and equipment	$	1,655,196		$	1,559,484

(1)

Under the financing method, the historical cost of the Haynesville Shale gas gathering system contributed to KinderHawk is carried at the full historical basis of the assets on the unaudited condensed consolidated balance sheets in “Gas gathering systems and equipment” and depreciated over the remaining useful life of the assets. As of September 30, 2013 and June 30, 2013, the table above includes approximately $444.3 million and $398.1 million, respectively, attributed to the net carrying value of the assets contributed to KinderHawk.

(2)

Under the financing method, the historical cost of the Eagle Ford Shale gas gathering systems contributed to EagleHawk is carried at the full historical basis of the assets on the unaudited condensed consolidated balance sheets in “Gas gathering systems and equipment” and depreciated over the remaining useful life of the assets. As of September 30, 2013 and June 30, 2013, the table above includes approximately $979.1 million and $909.4 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.

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.

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 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 September 30, 2013 and June 30, 2013, was approximately $1.9 billion and $1.9 billion, respectively, of which approximately $22.1 million and $20.9 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 $22.2 million and $30.4 million as “Restricted cash” at September 30, 2013 and June 30, 2013, 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 $5.6 million and $4.8 million as “Restricted Cash” at September 30, 2013 and June 30, 2013, respectively.

Marketing Revenue and Expense

Historically, a subsidiary of the Company purchased and sold the Company’s own and third party natural gas produced from wells which the Company and third parties operated. The revenues and expenses related to these marketing activities were reported on a gross basis as part of operating revenues and operating expenses in historical periods. Marketing revenues were recorded at the time natural gas was physically delivered to third parties at a fixed or index price. Marketing expenses attributable to gas purchases were recorded as the subsidiary of the Company took physical title to natural gas and transported the purchased volumes to the point of sale. The Company does engage, from time to time, in marketing operations when this meets the needs of the business.

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 operation 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

We account for goodwill in accordance with ASC 350, Intangibles—Goodwill and Other (ASC 350). 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 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.

In September 2011, the Financial Accounting Standards Board issued ASU No. 2011-08, Testing Goodwill for Impairment (ASU 2011-08) to simplify how companies test goodwill for impairment. ASU 2011-08 simplifies testing for goodwill impairments by allowing entities to first assess qualitative factors to determine whether the facts or circumstances lead to the conclusion that it is more likely than not that the fair value of a reporting unit is less than the carrying amount. If the entity concludes that it is not more likely than not that the fair value of a reporting unit is less than its carrying amount, then the entity does not have to perform the two-step impairment test. However, if that same conclusion is not reached, the company is required to perform the first step of the two-step impairment test. ASU 2011-08 also allows a company to bypass

the qualitative assessment and proceed directly with performing the two-step goodwill impairment test. The first step is to compare the fair value of a reporting unit with its carrying value, including goodwill. If the fair value of a reporting unit is less than its carrying value, then the second step of the test must be performed to measure the amount of the impairment loss, if any.

We perform our goodwill test annually during the quarter ending June 30 or more often if circumstances require. The last goodwill test was conducted during the 2013 fiscal year for inclusion in the Transition Report to Security Holders dated June 30, 2013. The test results at that time did not indicate impairment. Our qualitative assessment included an evaluation of factors such as macroeconomic conditions, industry and market considerations, cost factors, overall financial performance, as well as other relevant events and circumstances that affect the fair value or carrying amount. Based on this qualitative assessment, there were no impairment indicators that would indicate that it is more likely than not that the fair value of the Company’s oil and gas reporting unit is less than its carrying amount. As such, we did not perform the two-step goodwill impairment test during the six months ended June 30, 2013. In previous years, our goodwill impairment reviews consisted of the two-step process. The first step is to determine the fair value of our reporting unit and compare it to the carrying value of the related net assets. Fair value is determined based on our estimates of market values. If this fair value exceeds the carrying value no further analysis or goodwill write-down is required. The second step is required if the fair value of the reporting unit is less than the book value of the net assets. In this step, the implied fair value of the reporting unit is allocated to all the underlying assets and liabilities, including both recognized and unrecognized tangible and intangible assets, based on their fair values. If necessary, goodwill is then written-down to its implied fair value. If the fair value of the reporting unit is less than the book value (including goodwill), then goodwill is reduced to its implied fair value and the amount of the write down is charged against earnings. The assumptions we used in calculating our reporting unit fair values at the time of the test in prior years include our market capitalization and discounted future cash flows based on estimated reserves and production, future costs and future oil and natural gas prices. Material adverse changes to any of the factors considered could lead to an impairment of all or a portion of our goodwill in future periods.

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 the Impairment or Disposal of Long-Lived Assets Subsections of ASC Subtopic 360-10 (ASC 360-10). The Company reviews its intangible assets for potential impairment whenever events or changes in circumstances indicate that an “other-than-temporary” decline in the value of the investment has occurred.

There was no amortization expense during the three months ended September 30, 2013. Amortization expense was $2.8 million for the three months ended September 30, 2012, and was included in “Gathering, transportation and other” on the unaudited condensed consolidated statements of operations. Other intangible assets subject to amortization at September 30, 2013 and September 30, 2012 are as follows:


	September 30,		September 30,
	2013		2012
	(In thousands)
Transportation contracts	$	—	$	105,108
Less – accumulated amortization		—		(35,108	)

Net transportation contracts	$	—	$	70,000

Recently Issued Accounting Pronouncements

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 September 30, 2013, the ceiling test value of the Company’s reserves was calculated based on the first day average of the 12-months ended September 30, 2013, of the West Texas Intermediate (WTI) spot price of $95.20 per barrel or was calculated based equally on the respective first day average of the 12-months ended September 30, 2013, of the WTI spot price of $95.20 per barrel and the Light Louisiana Sweet (LLS) differential spot price of $14.42 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 September 30, 2013, of the Henry Hub price of $3.62 per million British thermal units (Mmbtu), adjusted by lease or field for energy content, transportation fees, and regional price differentials. Using these prices, the Company’s net book value of oil and natural gas properties at September 30, 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 June 30, 2013, the ceiling test value of the Company’s reserves was calculated based on the first day average of the 12-months ended June 30, 2013, of the West Texas Intermediate (WTI) spot price of $91.60 per barrel or was calculated based equally on the respective first day average of the 12-months ended June 30, 2013, of the WTI spot price of $91.60 per barrel and the Light Louisiana Sweet (LLS) differential spot price of $16.95 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 June 30, 2013 of the Henry Hub price of $3.47 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 June 30, 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.

3. LONG-TERM DEBT

Long-term debt as of September 30, 2013 and June 30, 2013, consisted of the following:


	September 30, 2013		June 30, 2013
	(In thousands)
6.25% $600 million senior notes	$	600,000	$	600,000
7.25% $1.2 billion senior notes ⁽¹⁾		1,230,275		1,230,501
10.5% $600 million senior notes⁽²⁾⁽³⁾		—		576,654
7.875% $800 million senior notes		799,611		799,611

	$	2,629,886	$	3,206,766

(1)	Amount includes a $5.3 million and $5.5 million premium at September 30, 2013 and June 30, 2013, 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 $13.0 million discount at June 30, 2013, 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.

(3)	The 10.5% Senior Notes are due in August 2014 and have been moved to the Current Liabilities section of the balance sheet under the name Current Debt. At September 30, 2013, the value shown of $579.5 million includes a discount of $10.1 million.

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 9, “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.

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 9, “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 $5.3 million and $5.5 million at September 30, 2013 and June 30, 2013, 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).

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 9, “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 $10.1 million and $13.0 million at September 30, 2013 and June 30, 2013, respectively.

As the 2014 Notes are due in less than one calendar year from the date of this report, the debt has been moved from Long Term Debt to the Current Liabilities section of the balance sheet under the title Current Debt. The amount shown there includes the remaining discount on the Note, which is $10.1 million as of September 30, 2013.

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 9, “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. At September 30, 2013 and June 30, 2013, the Company had approximately $29.2 million and $31.5 million, respectively, of debt issuance costs remaining that are being amortized over the lives of the respective debt.

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 September 30, 2013 or June 30, 2013. 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. If any financial assets or liabilities are acquired that would be accounted for at fair value, the Company’s assessment of the significance of a particular input to the fair value measurement would require judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

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 September 30, 2013 and June 30, 2013 (excluding premiums and discounts):


	September 30, 2013				June 30, 2013
Debt	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
	(In thousands)
10.5% $600 million senior notes		589,640		620,100		—		—

Current Debt		589,640		620,100		—		—

6.25% $600 million senior notes	$	600,000	$	659,250	$	600,000	$	657,948
7.25% $1.2 billion senior notes		1,225,000		1,335,250		1,225,000		1,306,463
7.875% $800 million senior notes		799,611		817,200		799,611		816,720
10.5% $600 million senior notes		—		—		589,640		631,200

Long Term Debt	$	2,624,611	$	2,811,700	$	3,214,251	$	3,412,331

Total Debt	$	3,214,251	$	3,431,800	$	3,214,251	$	3,412,331

The fair values of the Company’s fixed interest debt instruments were calculated using quoted market prices based on trades of such debt as of September 30, 2013 and June 30, 2013, respectively.

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 September 30, 2013 (in thousands):


Liability for asset retirement obligation as of June 30, 2013	$	156,083
Additions		6,565
Accretion expense		1,980
Revisions in estimated cash flows and other		—

Liability for asset retirement obligation as of September 30, 2013	$	164,628

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 $2.3 million and $7.6 million for the three months ended September 30, 2013 and 2012, respectively.

As of September 30, 2013, the Company had the following commitments:


	Total Obligation Amount		Years Remaining
	(in thousands)
Gathering and transportation commitments	$	3,235,825		16
Drilling rig commitments		582,807		5
Non-cancelable operating leases		9,679		5
Pipeline and well equipment obligations		52,053		1
Various contractual commitments (including, among other things, rental equipment obligations, obtaining and processing seismic data)		109,553		1

Total commitments	$	3,989,917

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. 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 2013 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. No such fee has been paid to date.

As previously discussed, the Company has certain amounts associated with the sale of its interests in KinderHawk and EagleHawk recorded as financing obligations in the unaudited condensed consolidated balance sheets, which are not reflected in the amounts shown in the table above. The balance of the Company’s financing obligations as of September 30, 2013 and June 30, 2013, was approximately $1.9 billion and $1.9 billion, respectively, of which approximately $22.1 million and $20.9 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. 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.

8. ADDITIONAL FINANCIAL STATEMENT INFORMATION

Certain balance sheet amounts are comprised of the following:


	September 30, 2013			June 30, 2013
	(In thousands)
Accounts receivable:
Oil and natural gas revenues	$	266,042		$	248,631
Joint interest accounts		285,191			221,573
Income and other taxes receivable		15,094			12,055
Other		25,926			40,998

	$	592,253		$	523,257

Prepaids and other:
Prepaid insurance	$	244		$	279
Prepaid drilling costs		35,370			29,323
Other		12,979			3,770

	$	48,593		$	33,372

Accounts payable and accrued liabilities:
Trade payables	$	39,669		$	167,023
Revenues and royalties payable		217,172			214,517
Accrued oil and natural gas capital costs		539,389			726,179
Accrued midstream capital costs		96,693			125,558
Accrued interest expense		55,157			67,721
Prepayment liabilities		50,665			7,820
Payable to Parent		45,232			31,510
Accrued lease operating expenses		15,670			16,388
Accrued ad valorem taxes payable		29,945			16,733
Accrued production taxes payable		8,273			11,272
Accrued gathering, transportation and other expenses		102,968			72,534
Accrued employee compensation		4,018			3,365
Income taxes payable		(1,196	)		(1,485	)
Other		83,411			99,680

	$	1,287,066		$	1,558,815

9. 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.

The following table presents statement of operations information for EagleHawk for the three months ended September 30, 2013 and 2012:


	Three Months Ended September 30, 2013			Three Months Ended September 30, 2012
Operating revenues:
Midstream	$	13,065		$	14,476

Total operating revenues		13,065			14,476

Operating expenses:
Taxes other than income		1,844			1,108
Gathering, transportation and other		11,089			6,355
General and administrative		555			469
Depletion, depreciation and amortization		7,447			4,601

Total operating expenses		20,935			12,533

Gain (Loss) from operations		(7,870	)		1,943
Other income (expenses):
Interest expense and other		(2,669	)		(3,980	)

Total other income (expenses)		(2,669	)		(3,980	)

Loss from continuing operations before income taxes		(10,539	)		(2,037	)
Income tax benefit		4,598			801

Net gain (loss)	$	(5,941	)	$	(1,236	)

The following table presents balance sheet information for EagleHawk as of September 30, 2013 and September 30, 2012:


	September 30, 2013			June 30, 2013
Current assets:
Cash	$	22,268		$	30,433
Accounts receivable		25,718			35,643
Prepaids and other		6,942			9

Total current assets		54,928			66,085

Other operating property and equipment:
Gas gathering systems and equipment		1,020,703			943,153
Other operating assets		1,089			954

Gross other operating property and equipment		1,021,792			944,107
Less—accumulated depreciation		(41,593	)		(34,145	)

Net other operating property and equipment		980,199			909,962

Other noncurrent assets:
Deferred income taxes		4,598			9,269

Total assets	$	1,039,725		$	985,316

Current liabilities:
Accounts payable and accrued liabilities	$	104,774		$	147,187

Total current liabilities		104,774			147,187

Long-term debt		—			—
Other noncurrent liabilities
Payable to affiliate		338,775			294,858
Asset retirement obligations		13,008			13,008
Other		—			—
Stockholders’ equity:
Additional paid-in capital		629,949			561,834
Accumulated deficit		(46,781	)		(31,571	)

Total stockholders’ equity		583,168			530,263

Total liabilities and stockholders’ equity	$	1,039,725		$	985,316

The following table presents cash flow statement information for EagleHawk for the three months ended September 30, 2013 and 2012:


	Three Months Ended September 30,
	2013			2012
Cash flows from operating activities:
Net loss	$	(5,941	)	$	(1,236	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depletion, depreciation and amortization		7,447			4,601
Income tax expense (benefit)		(4,671	)		(801	)
Other operating		74			(1	)
Change in assets and liabilities:
Accounts receivable		9,925			6,203
Prepaid and other		(6,933	)		39
Accounts payable and accrued liabilities		(42,413	)		21,174

Net cash used in operating activities		(42,512	)		29,979

Cash flows from investing activities:
Other operating property and equipment capital expenditures		(77,685	)		(92,372	)

Net cash used in investing activities		(77,685	)		(92,372	)

Cash flows from financing activities:
Payable to affiliate		43,917			20,024
Contributions from affiliate		86,250			30,888
Distributions to affiliate		(18,135	)		(11,004	)

Net cash provided by financing activities		112,032			39,908

Net increase (decrease) in cash		(8,165	)		(22,485	)
Cash at beginning of period		30,433			55,327

Cash at end of period	$	22,268		$	32,842

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 Energy Corporation 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.

10. RELATED PARTY ARRANGEMENTS AND TRANSACTIONS

Effective January 1, 2013, the Company entered into the Management Services Agreement with BHP Billiton Limited, the parent company of Petrohawk, for BHP Billiton Limited to provide various personnel and payroll services as set forth in the agreement. Former employees of the Company transferred to become employees of BHP Billiton Limited, providing services to the Company and the Company reimburses BHP Billiton Limited for the costs of these services. The total costs incurred under this agreement with BHP Billiton Limited for the three months ended September 30, 2013, were $96.1 million. For the current quarter ended September 30, 2013 and for unsettled prior period activity, $82.3 million of cash payments were made between Petrohawk and BHP Billiton Limited, the parent company of Petrohawk. As a result, the total amount payable to BHP Billiton Limited as of September 30, 2013, is $45.2 million. The following table summarizes the location of the $96.1 million of costs in the Company’s consolidated financial statements:


Consolidated Financial	Location of Costs	Amount
		(in thousands)
Balance Sheets	Oil and natural gas properties	$	18,787
Balance Sheets	Gas gathering systems and equipment		1,131
Balance Sheets	Stockholders’ Equity		400
Statements of Operations	General and administrative		56,359
Statements of Operations	Lease operating		11,673
Statements of Operations	Gathering, transportation and other		7,708

		$	96,058

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 September 30, 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 Transition Report to Security Holders dated June 30, 2013.

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 hydrocarbons predominantly from oil and gas shale properties located in the United States. As further discussed in Note 1 “Financial Statement Presentation,” on August 25, 2011, BHP Billiton Limited, a corporation organized under the laws of Victoria, Australia (BHP Billiton Limited), acquired 100% of our outstanding shares of common stock through the merger of a wholly owned subsidiary of BHP Billiton Petroleum (North America) Inc., a Delaware corporation and wholly owned subsidiary of BHP Billiton Limited, with and into Petrohawk, with Petrohawk continuing as the surviving entity. At the date of this report, Petrohawk remains an indirect, wholly owned subsidiary of BHP Billiton Limited (our parent).

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, prior to the acquisition by BHP Billiton Limited, have been internally generated cash flows from operations, proceeds from asset sales, capital market issuances of debt and equity, and availability under a former, now cancelled, Senior Credit Agreement. As of the date of acquisition by BHP Billiton Limited, our capital resources and liquidity have been and will continue to be 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.

The Company engages in acquisitions and divestitures from time to time to rationalize and further develop our portfolio of shale assets. The Company has engaged Scotia Bank to pursue a possible divestment of certain land in the Permian, including acreage in both the Delaware and Midland Basins, for which no sale has yet been agreed.

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 Transition Report to Security Holders dated June 30, 2013.

Comparison of Results of Operations

Three Months Ended September 30, 2013 Compared to Three Months Ended September 30, 2012

We reported income from continuing operations, net of income taxes, of $10.9 million for the three months ended September 30, 2013, compared to a loss from continuing operations, net of income taxes, of $32.7 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 September 30,
(In thousands (except per unit and per Mcfe amounts))	2013			2012			Change
Income (loss) from continuing operations, net of income taxes	$	10,938		$	(32,666	)	$	43,604
Operating revenues:
Oil and natural gas		841,839			502,475			339,364
Marketing		98,351			5,329			93,022
Midstream		12,228			17,804			(5,576	)
Operating expenses:
Marketing		97,925			4,976			92,949
Production:
Lease operating		53,567			22,777			30,790
Workover and other		7,459			4,409			3,050
Taxes other than income		41,801			17,191			24,610
Gathering, transportation and other		125,444			75,995			49,449
General and administrative		69,149			35,500			33,649
Depletion, depreciation and amortization:
Depletion – Full cost		344,135			293,335			50,800
Depreciation – Midstream		12,846			8,601			4,245
Depreciation – Other		9,588			9,693			(105	)
Rig contract termination costs		61,378			—			61,378
Accretion expense		1,980			599			1,381
Other income (expenses):
Net gain on derivative contracts		—			—			—
Interest expense and other		(107,743	)		(107,530	)		213
Income from continuing operations before income taxes		19,403			(54,998	)		74,401
Income tax benefit (expense)		(8,465	)		22,332			13,867

Production:
Natural gas – Mmcf		79,218			84,769			(5,551	)
Crude oil – MBbl		5,016			2,351			2,665
Natural gas liquids – MBbl		2,557			1,539			1,018
Natural gas equivalent – Mmcfe⁽¹⁾		124,656			108,108			16,548
Average daily production – Mmcfe⁽¹⁾		1,355			1,175			180

Average price per unit ⁽²⁾:
Natural gas price – Mcf	$	3.33		$	2.67		$	0.34
Crude oil price – Bbl		101.30			96.31			4.99
Natural gas liquids price – Bbl		28.08			31.36			(3.28	)
Natural gas equivalent price – Mcfe⁽¹⁾		6.77			4.64			2.13

Average cost per Mcfe:
Production:
Lease operating		0.43			0.21			0.22
Workover and other		0.06			0.04			0.02
Taxes other than income		0.34			0.16			0.18
Gathering, transportation and other		1.01			0.70			0.31
General and administrative		0.55			0.33			0.22
Depletion (excludes depreciation and amortization)		2.76			2.71			0.05

(1)	Oil and natural gas liquids are converted to equivalent gas production using a 6:1 equivalent ratio. This ratio does not assume price equivalency and given price differentials, the price for a barrel of oil equivalent for natural gas may differ significantly from the price for a barrel of oil.

(2)	Amounts exclude the impact of cash paid/received on settled contracts as we did not elect to apply hedge accounting.

For the three months ended September 30, 2013, oil and natural gas revenues increased $339.4 million from the same period in 2012, to $841.8 million. The increase was primarily due to the increase in crude oil and natural gas liquids (NGLs) volumes of 113.3% and 66.2%, respectively which offset a 6.5% decline in natural gas production. The change in volumes added $273.4 million in revenue. Price movements also contributed positively to revenues, with crude oil and natural gas rising $4.99 per barrel and $0.66 per mmcf, respectively. NGL prices dropped 10.5% or $3.28 to $28.08 per barrel versus the same period in 2012. The change in prices added $68.9 million in revenue. Other revenue dropped $2.9 million for the three months ended September 30, 2013 vs. September 30, 2012.

We had marketing revenues of $98.4 million and marketing expenses of $98.0 million for the three months ended September 30, 2013, resulting in income before income taxes of $0.4 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 $38.2 million for the three months ended September 30, 2013, compared to the same period in 2012 of $34.1 million, an increase of $4.1 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 September 30, 2013, approximately $12.2 million in revenues, after intercompany eliminations, were reported in midstream revenues on the unaudited condensed consolidated statements of operations, a decrease of $5.5 million from the prior year. This decrease is attributed to a decline in trucking transportation services between periods.

Lease operating expenses increased $30.8 million for the three months ended September 30, 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 $0.22 per Mcfe to $0.43 per Mcfe in 2013 from $0.21 per Mcfe in 2012.

Taxes other than income increased $24.6 million for the three months ended September 30, 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 and resulting impact on indirect taxes 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 September 30, 2013, we recorded severance tax refunds totaling $7.1 million compared to $4.7 million in the prior year. On a per unit basis, excluding the severance tax refunds, taxes other than income were $0.39 per Mcfe in 2013 compared to $0.20 per Mcfe in 2012.

Gathering, transportation and other expense increased $49.4 million for the three months ended September 30, 2013 as compared to the same period in 2012. On a per unit basis, gathering transportation and other increased $0.31 per Mcfe from $0.70 per Mcfe in 2012 to $1.01 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.

During the quarter, the Company continued to make modifications to the number of rigs within our rig fleet. As such, we incurred costs of approximately $61.4 million associated with the early termination of select rig contracts. This expense was recorded to “Rig contract termination costs” in the consolidated statements of operations.

General and Administrative expense increased $33.6 million for the three months ended September 30, 2013 as compared to the same period in 2012. Salaries & compensation increased $24.7 million primarily due to increased operational support due to the increased number of wells and related infrastructure. Marketing support increased by $3.5 million and third party technical subscription services rose by $3.0 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 increased $50.8 million for the three months ended September 30, 2013, from the same period in 2012, to $344.1 million. On a per unit basis, depletion expense increased $0.05 per Mcfe to $2.76 per Mcfe. The increase 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 September 30, 2013.

Depreciation expense associated with our gas gathering systems increased $4.2 to $12.8 million for the three months ended September 30, 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. Depreciation expense associated with our other operating property and equipment decreased $0.1 million to $9.6 million for the three months ended September 30, 2013, as compared to the same period in 2012.

Interest expense and other increased $0.2 million for the three months ended September 30, 2013 compared to the same period in 2012. There was a reduction in interest expense recorded as a 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 September 30, 2013, we recorded approximately $40.4 million of interest expense on the financing obligations compared to $40.8 million in the prior year.

We had an income tax expense of $8.5 million for the three months ended September 30, 2013, due to our income from operations before income taxes of $19.4 million compared to an income tax benefit of $22.3 million due to our loss from operations before income taxes of $55.0 million in the prior year. The effective tax rate for the three months ended September 30, 2013, was 43.6% compared to 40.6% for the three months ended September 30, 2012.

Investment in EagleHawk

EagleHawk had gross revenues of $31.6 million related to its Eagle Ford Shale gathering and treating systems in the Hawkville and Black Hawk Fields for the three months ended September 30, 2013, compared to $23.9 million for the three months ended September 2012. Gross revenues include $18.5 million and $9.4 million of intercompany revenues that were eliminated in consolidation for the three months ended September 30, 2013 and 2012, respectively. Total operating expenses for EagleHawk for the three months ended September 30, 2013, of $20.9 million included $11.1 million in gathering, transportation and other expenses and $7.4 million in depreciation expense. Total operating expenses for the three months ended September 2012, of $12.5 million included $6.4 million in gathering, transportation and other expenses and $4.6 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.

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.