BHP Group Limited — Interim / Quarterly Report 2014

Feb 18, 2014

6-K 1 d677916d6k.htm FORM 6-K 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

February 14, 2014

BHP BILLITON LIMITED	BHP BILLITON PLC
(ABN 49 004 028 077)	(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)
171 COLLINS STREET, MELBOURNE, VICTORIA 3000
AUSTRALIA	NEATHOUSE PLACE, 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 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.

	● — BHP Billiton Limited	BHP Billiton Plc
	171 Collins Street	Neathouse Place
	Melbourne Victoria 3000 Australia	London SW1V 1LH UK
	GPO BOX 86	Tel +44 20 7802 4000
	Melbourne Victoria 3001 Australia	Fax + 44 20 7802 4111
	Tel +61 1300 554 757 Fax +61 3 9609 3015	bhpbilliton.com
14 February 2014	bhpbilliton.com

To:	New York Stock Exchange
London Stock Exchange	JSE Limited

PETROHAWK DECEMBER 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 December 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

●
Nicole Duncan
Company Secretary
BHP Billiton

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 Australia	Registered Office: Neathouse Place London SW1V 1LH United Kingdom

The BHP Billiton Group is headquartered in Australia

PETROHAWK ENERGY CORPORATION

QUARTERLY REPORT TO SECURITY HOLDERS

DECEMBER 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, 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 second quarter report for the fiscal year ending June 30, 2014.

2

PETROHAWK ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(In thousands)

	Three months Ended Dec 31, — 2013		2012		Six months Ended Dec 31, — 2013		2012
Operating revenues:
Oil and natural gas	$ 686,818		$ 555,813		$ 1,528,657		$ 1,058,288
Marketing	126,061		2,122		224,412		7,451
Midstream	16,001		17,315		28,229		35,119
Total operating revenues	828,880		575,250		1,781,298		1,100,858
Operating expenses:
Marketing	130,774		1,908		228,698		6,884
Production:
Lease operating	115,465		21,780		169,032		44,557
Workover and other	9,853		1,631		17,312		6,040
Taxes other than income	39,104		28,222		80,905		45,413
Gathering, transportation and other	128,808		82,455		254,253		158,450
General and administrative	77,121		45,334		146,271		80,833
Depletion, depreciation and amortization	323,149		282,565		689,718		594,194
Impairment of intangible asset	—		67,237		—		67,237
Rig contract termination costs	13,585		—		74,963		—
Accretion expense	2,086		599		4,066		1,200
Total operating expenses	839,945		531,731		1,665,218		1,004,808
Income (loss) from operations	(11,065	)	43,519		116,080		96,050
Other income (expenses):
Interest expense and other	(104,726	)	(110,103	)	(212,469	)	(217,633	)
Total other income (expenses)	(104,726	)	(110,103	)	(212,469	)	(217,633	)
Income (loss) from continuing operations before income taxes	(115,791	)	(66,584	)	(96,389	)	(121,583	)
Income tax benefit (expense)	44,089		26,593		35,624		48,925
Net income (loss)	$ (71,702	)	$ (39,991	)	$ (60,765	)	$ (72,658	)

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)

	December 31, 2013
Current assets:
Cash	$ 121,079	$	214,990
Accounts receivable	923,247		523,257
Deferred income tax	54,744		9,950
Prepaid and other	35,515		33,372
Total current assets	1,134,585		781,569
Oil and natural gas properties (full cost method):
Evaluated	17,545,876		15,329,505
Unevaluated	2,822,500		3,010,761
Gross oil and natural gas properties	20,368,376		18,340,266
Less – accumulated depletion	(7,948,638	)	(7,297,291	)
Net oil and natural gas properties	12,419,738		11,042,975
Other operating property and equipment:
Gas gathering systems and equipment	1,864,615		1,648,198
Other operating assets	130,188		138,027
Gross other operating property and equipment	1,994,803		1,786,225
Less – accumulated depreciation	(208,738	)	(168,367	)
Net other operating property and equipment	1,786,065		1,617,858
Other noncurrent assets:
Goodwill	932,802		932,802
Debt issuance costs, net of amortization	26,836		31,463
Deferred income taxes	342,336		351,506
Restricted cash	24,799		35,236
Other	6,021		13,676
Total assets	$ 16,673,182	$	14,807,085
Current liabilities:
Accounts payable and accrued liabilities	$ 2,099,535	$	1,558,815
Payable to financing arrangements	25,630		20,894
Current debt	1,382,094		—
Total current liabilities	3,507,259		1,579,709
Long-term debt	1,830,275		3,206,766
Other noncurrent liabilities:
Asset retirement obligations	173,402		156,083
Payable on financing arrangements	1,896,879		1,871,584
Other	413		415
Commitments and contingencies (Note 6)
Stockholders’ equity:
Common stock: 100 shares of $.001 par value authorized, issued and outstanding at December 31, 2013 and June 30,
2013	—		—
Additional paid-in capital	10,507,398		9,174,208
Accumulated deficit	(1,242,444	)	(1,181,680	)
Total stockholders’ equity	9,264,954		7,992,528
Total liabilities and stockholders’ equity	$ 16,673,182	$	14,807,085

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 September 30, 2013	—	$ —	$ 10,322,019	$ (1,170,742	)	$ 9,151,277
Contribution from parent (1)	—	—	185,379	—		185,379
Net income	—	—	—	(71,702	)	(71,702	)
Balance at December 31, 2013	—	$ —	$ 10,507,398	$ (1,242,444	)	$ 9,264,954

(1) Includes both cash funding and non-cash contributions from BHP Billiton Limited. The cash funding for the six months ended December 31, 2013, totals approximately $1.3 billion.

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)

	Six Months Ended December 31, — 2013		2012
Cash flows from operating activities:
Net income (loss)	$ (60,765	)	$ (72,658	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation and amortization	689,718		594,193
Accretion expense	4,066		1,198
Income tax expense (benefit)	(35,624	)	(48,924	)
Write down of midstream assets and loss on sale	—		67,237
Net Unrealized loss (gain) on derivative contracts	—		(17,520	)
Other operating	30,341		23,572
Change in assets and liabilities:	—		—
Accounts receivable	(399,990	)	(51,405	)
Prepaid and other	(2,143	)	357
Accounts payable and accrued liabilities	974,206		(156,803	)
Other	1,998		1,322
Net cash provided by operating activities	1,201,807		340,569
Cash flows from investing activities:
Oil and natural gas capital expenditures	(2,715,234	)	(1,660,517	)
Increase in restricted cash	(225,654	)	(323,305	)
Decrease in restricted cash	236,091		350,985
Other operating property and equipment capital expenditures	46,285		(247,850	)
Other	—		—
Net cash used in investing activities	(2,658,512	)	(1,880,687	)
Cash flows from financing activities:
Contribution from parent	1,345,217		1,490,350
Repayment of borrowings	—		17,520
Increase in payable on financing arrangements	34,974		32,796
Decrease in payable on financing arrangements	(17,399	)	(17,324	)
Other	2		—
Net cash provided by financing activities	1,362,794		1,523,342
Net increase (decrease) in cash	(93,911	)	(16,776	)
Cash at beginning of period	214,990		112,898
Cash at end of period	$ 121,079		$ 96,122

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 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

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.

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 second quarter report for the fiscal year ending June 30, 2014.

7

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 six months ended December 31, 2013 or for the six months ended December 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 BHP Billiton Petroleum (Eagle Ford Gathering) LLC (BHP Eagle Ford Gathering), formerly known as EagleHawk Field Services LLC, to KM Eagle Gathering LLC (Eagle Gathering). The BHP Eagle Ford Gathering 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 BHP Eagle Ford Gathering 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 BHP Eagle Ford Gathering 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 December 31, 2013 and June 30, 2013 consisted of the following:

	December 31, 2013
	(In thousands)
Gas gathering systems and equipment	$ 1,864,615	$	1,648,198
Less – accumulated depreciation	(111,134	)	(88,714	)
Net gas gathering systems and equipment	$ 1,753,481	$	1,559,484

8

(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 December 31, 2013 and June 30, 2013, the table above includes approximately $390.7 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 BHP Eagle Ford Gathering 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 December 31, 2013 and June 30, 2013, the table above includes approximately $1,069.6 million and $909.4 million, respectively, attributed to the net carrying value of the assets contributed to BHP Eagle Ford Gathering.

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 BHP Eagle Ford Gathering 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 BHP Eagle Ford Gathering 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.

9

The balance of the Company’s financing obligations as of December 31, 2013 and June 30, 2013, was approximately $1.9 billion and $1.9 billion, respectively, of which approximately $25.6 million and $20.9 million was classified as current for the respective periods.

Restricted Cash

In conjunction with the termination of the BHP Eagle Ford Gathering Revolving Credit Agreement during 2011, BHP Eagle Ford Gathering began issuing cash calls in accordance with each party’s membership interest to the Company and Kinder Morgan in order to fund Eagle Ford Gathering’s capital expenditures needs. Since BHP Eagle Ford Gathering’s cash balances are restricted for the purpose of funding its capital program, the Company presented BHP Eagle Ford Gathering’s cash of approximately $18.9 million and $30.4 million as “Restricted cash” at December 31, 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 $5.9 million and $4.8 million as “Restricted Cash” at December 31, 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 BHP Eagle Ford Gathering 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 BHP Eagle Ford Gathering’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.

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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 six months ended December 31, 2013. Amortization expense was $5.6 million for the six months ended December 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 had 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 during the period ending December 31, 2012.

Intangible assets subject to amortization at June 30, 2012, December 31, 2012 and December 31, 2013 are as follows:

	2012
	(In thousands)
Transportation contracts – gross book value at June 30	$ 105,108	$	—
Less – accumulated amortization at June 30	(32,345	)	—
Less – amortization of six months to December 31	(5,526	)	—
Less – Impairment of Kaiser contract	(67,237	)	—
Net transportation contracts at December 31	$ —	$	—

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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.

No other pronouncements made during calendar year 2013 are anticipated to impact Petrohawk.

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 December 31, 2013, the ceiling test value of the Company’s reserves was calculated based on the first day average of the 12-months ended December 31, 2013, of the West Texas Intermediate (WTI) spot price of $97.03 per barrel or was calculated based equally on the respective first day average of the 12-months ended December 31, 2013, of the WTI spot price of $97.03 per barrel and the Light Louisiana Sweet (LLS) differential spot price of $10.18 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 December 31, 2013, of the Henry Hub price of $3.68 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 December 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 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.

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3. LONG-TERM DEBT

On January 2, 2014, the Company issued a formal notice of redemption to noteholders of its 10.5% Senior Notes due 2014 and 7.875% Senior Notes due 2015. All outstanding Senior Notes due 2014 and 2015 were redeemed on February 3, 2014 at the applicable call prices. The total aggregate principal value of the notes to be redeemed is approximately $1.4 billion US Dollars. As a result, we have classified the Senior Notes due 2015 as short term debt. During the quarter ending September 30, 2013, we classified the 10.5% Senior Notes due 2014 as short term debt.

Long-term debt as of December 31, 2013 and June 30, 2013, consisted of the following:

	December 31, 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 (3)	—	799,611
	$ 1,830,275	$ 3,206,766

(1) Amount includes a $5.0 million and $5.5 million premium at December 31, 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 . Similarly, the 7.875% Senior Notes have been moved to the Current Liabilities section of the balance sheet under the name Current Debt . Both Senior Notes were called for redemption in early January 2014 and settled on February 3, 2014.

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 (Proliq, Inc. and BHP Eagle Ford Gathering, LLC), as discussed in Note 9, “BHP Eagle Ford Gathering (formerly 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.

On or prior to June 1, 2014, the Company may redeem up to 35% of the aggregate principal amount of the 2019 Notes with the net cash proceeds of certain equity offerings at a redemption price of 106.25% of the principal amount, plus accrued and unpaid interest to the redemption date; provided that at least 65% in aggregate principal of the 2019 Notes originally issued under the 2019 Indenture remain outstanding immediately after the redemption. In addition, on or prior to June 1, 2015, the Company may redeem all or part of the 2019 Notes at a redemption price equal to the principal amount, plus accrued and unpaid interest, plus a make whole premium equal to the excess, if any of (a) the present value at such time of (i) the redemption price of such note at June 1, 2015 plus (ii) any required interest payments due on such note through June 1, 2015 (except for currently accrued and unpaid interest), computed using a discount rate equal to the Treasury Rate plus 50 basis points, discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months), over (b) the principal amount of such Note.

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On or after June 1, 2015, the Company may redeem all or a part of the 2019 Notes at any time or from time to time, at the redemption prices (expressed as percentages of principal amount) set forth in the following table plus accrued and unpaid interest, if any, to the applicable redemption date, if redeemed during the 12-month period beginning on June 1 of the years indicated below:

Year
2015	103.125
2016	101.563
2017	100.000

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 (Proliq, Inc. and BHP Eagle Ford Gathering, LLC), as discussed in Note 9, “BHP Eagle Ford Gathering (formerly 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.

On or prior to August 15, 2013, the Company may redeem up to 35% of the aggregate principal amount of the 2018 Notes with the net cash proceeds of certain equity offerings at a redemption price of 107.25% of the principal amount, plus accrued and unpaid interest to the redemption date; provided that at least 65% in aggregate principal amount of the 2018 Notes originally issued under the 2018 Indenture remain outstanding immediately after the redemption. In addition, at any

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time prior to August 15, 2014, the Company may redeem some or all of the 2018 Notes for the principal amount, plus accrued and unpaid interest, plus a make whole premium equal to the excess, if any of (a) the present value at such time of (i) the redemption price of such note at August 15, 2014, (ii) any required interest payments due on the notes (except for currently accrued and unpaid interest), computed using a discount rate equal to the Treasury Rate plus 50 basis points, discounted to the redemption date on a semi-annual basis, over (b) the principal amount of such note.

On or after August 15, 2014, the Company may redeem all or part of the 2018 Notes at any time or from time to time at the redemption prices (expressed as a percentage of principal amount) set forth in the following table plus accrued and unpaid interest, if any, to the applicable redemption date, if redeemed during the 12-month period beginning August 15 of the years indicated below:

Year
2014	103.625
2015	101.813
2016 and thereafter	100.000

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 $5.0 million and $5.5 million at December 31, 2013 and June 30, 2013, respectively.

10.5% Senior Notes (now classified as Short Term Debt)

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 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. Petrohawk Energy Corporation, the issuer of the Notes, has no material independent assets or operations apart from the assets and operations of its subsidiaries.

The Company may redeem some or all of the 2014 Notes at any time or from time to time at the redemption prices (expressed as a percentage of principal amount) set forth in the following table plus accrued and unpaid interest, if any, to the applicable redemption date, if redeemed during the 12-month period beginning February 1 of the years indicated below:

Year
2013	105.250
2014	100.000

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

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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. 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 $7.2 million and $13.0 million at December 31, 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 $7.2 million as of December 31, 2013 as noted above. Also as noted at the beginning of Note 3, these Notes were called for redemption and were settled on February 3, 2014.

7.875% Senior Notes (now classified as Short Term Debt)

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 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. Petrohawk Energy Corporation, the issuer of the Notes, has no material independent assets or operations apart from the assets and operations of its subsidiaries.

The Company may redeem up to 35% of the aggregate principal amount of the 2015 Notes with the net cash proceeds of certain equity offerings at a redemption price of 107.875% of the principal amount plus accrued interest and unpaid interest to the redemption date provided that: at least 65% in aggregate principal amount of the 2015 Notes originally issued under the 2015 Indenture remain outstanding immediately after the redemption.

The Company may redeem some or all of the 2015 Notes at any time or from time to time at the redemption prices (expressed as a percentage of principal amount) set forth in the following table plus accrued and unpaid interest, if any, to the applicable redemption date, if redeemed during the 12-month period beginning June 1 of the years indicated below:

Year
2013	101.969
2014	100.000

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

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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 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. 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.

As noted at the beginning of Note 3, the 2015 Notes were called for redemption and settled on February 3, 2014. As a result for presentation in these financial statements, these Notes were moved from Long Term Debt to the Current Liabilities section of the balance sheet under the title Current Debt.

Debt Issuance Costs

The Company capitalizes certain direct costs associated with the issuance of long-term debt. At December 31, 2013 and June 30, 2013, the Company had approximately $26.8 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 December 31, 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.

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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 December 31, 2013 and June 30, 2013 ( excluding premiums and discounts ):

Debt	December 31, 2013 — Carrying Amount	Estimated Fair Value	June 30, 2013 — Carrying Amount	Estimated Fair Value
	(In thousands)
10.5% $600 million senior notes	$ 589,640	$ 617,850	—	—
7.875% $800 million senior notes	799,611	822,160	—	—
Current Debt	$ 1,389,251	$ 1,440,010	—	—
6.25% $600 million senior notes	$ 600,000	$ 661,500	$ 600,000	$ 657,948
7.25% $1.2 billion senior notes	1,225,000	1,321,469	1,225,000	1,306,463
7.875% $800 million senior notes	—	—	799,611	816,720
10.5% $600 million senior notes	—	—	589,640	631,200
Long Term Debt	$ 1,825,000	$ 1,982,969	$ 3,214,251	$ 3,412,331
Total Debt	$ 3,214,251	$ 3,422,979	$ 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 December 31, 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 six months ended December 31, 2013 (in thousands):

Liability for asset retirement obligation as of June 30, 2013	$
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
Additions	6,688
Accretion expense	2,086
Revisions in estimated cash flows and other	—
Liability for asset retirement obligation as of December 31, 2013	$ 173,402

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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.

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

	Total Obligation	Years
	Amount	Remaining
	(in thousands)
Gathering and transportation commitments	$ 3,162,366	15
Drilling rig commitments	529,472	6
Non-cancelable operating leases	14,122	6
Pipeline and well equipment obligations	51,588	1
Various contractual commitments (including, among other things, rental equipment obligations, obtaining and processing seismic
data)	72,152	1
Total commitments	$ 3,829,700

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:

	Minimum
	Annual
Contract Year	Quantity (Bcf)
Year 1 (partial)—2010	81.090
Year 2—2011	152.899
Year 3—2012	238.595
Year 4—2013	324.047
Year 5—2014	368.614
Year 6 (partial)—2015	143.066

These volumes represent 50% of the Company’s anticipated production from the specified acreage at the time the Company entered into the contract.

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. During the six months ended December 31, 2013, the company has incurred $36.5 million in deficiency payments related to not delivering the minimum quantities required by the KinderHawk contract with Kinder Morgan.

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As previously discussed, the Company has certain amounts associated with the sale of its interests in KinderHawk and BHP Eagle Ford Gathering 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 December 31, 2013 and June 30, 2013, was approximately $1.9 billion and $1.9 billion, respectively, of which approximately $25.6 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.

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8. ADDITIONAL FINANCIAL STATEMENT INFORMATION

Certain balance sheet amounts are comprised of the following:

	December 31, — 2013	2013
	(In thousands)
Accounts receivable:
Oil and natural gas revenues	$ 348,213	$	248,631
Joint interest accounts	284,607		221,573
Income and other taxes receivable	(676	)	12,055
Other	291,103		40,998
	$ 923,247	$	523,257
Prepaids and other	$ 35,515	$	33,372
Accounts payable and accrued liabilities:
Trade payables	$ 217,290	$	167,023
Revenues and royalties payable	189,689		214,517
Accrued oil and natural gas capital costs	1,021,581		726,179
Accrued midstream capital costs	169,605		125,558
Accrued interest expense	12,567		67,721
Taxes payable	124,909		28,005
Accrued employee compensation	(1,871	)	3,365
Income taxes payable	(1,196	)	(1,485	)
Other	366,961		227,932
	$ 2,099,535	$	1,558,815

9. BHP EAGLE FORD GATHERING ( FORMERLY EAGLEHAWK FIELD SERVICES )

On July 1, 2011, the Company along with its subsidiaries BHP Billiton Petroleum (Tx Gathering) LLC ( BHP Texas Gathering) (formerly Hawk Field Services) and BHP Billiton Petroleum (Eagle Ford Gathering) LLC (BHP Eagle Ford Gathering) (formerly EagleHawk Field Services, LLC) , closed previously announced transactions with KM Eagle Ford Gathering LLC, an affiliate of Kinder Morgan Energy Partners, including the transfer by BHP Texas Gathering of a 25% interest in Eagle Ford Gathering to KM Eagle Ford Gathering LLC in exchange for cash consideration of approximately $93 million.

BHP Eagle Ford Gathering, which is managed by BHP Texas Gathering, 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 BHP Eagle Ford Gathering.

BHP Eagle Ford Gathering 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 BHP Eagle Ford Gathering 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 BHP Eagle Ford Gathering for the six months ended December 31, 2013 and 2012:

	Six months Ended — December 31, 2013		Six months Ended — December 31, 2012
Operating revenues:
Midstream	$ 28,227		$ 28,923
Total operating revenues	28,227		28,923
Operating expenses:
Taxes other than income	2,444		2,215
Gathering, transportation and other	18,252		12,105
General and administrative	535		926
Depletion, depreciation and amortization	15,692		9,905
Total operating expenses	36,923		25,151
Gain (Loss) from operations	(8,696	)	3,772
Other income (expenses):
Interest expense and other	(15,498	)	(9,182	)
Total other income (expenses)	(15,498	)	(9,182	)
Income (loss) from continuing operations before income taxes	(24,194	)	(5,410	)
Income tax (expense) benefit	9,581		2,109
Net gain (loss)	$ (14,613	)	$ (3,301	)

The following table presents balance sheet information for BHP Eagle Ford Gathering as of December 31, 2013 and June 30, 2013:

	December 31, — 2013	2013
Current assets:
Cash	$ 18,897	$	30,433
Accounts receivable	19,397		35,643
Prepaids and other	6,942		9
Total current assets	45,236		66,085
Other operating property and equipment:
Gas gathering systems and equipment	1,123,240		943,153
Other operating assets	5,130		954
Gross other operating property and equipment	1,128,370		944,107
Less—accumulated depreciation	(48,359	)	(34,145	)
Net other operating property and equipment	1,080,011		909,962
Other noncurrent assets:
Deferred income taxes	9,581		9,269
Total assets	$ 1,134,828	$	985,316
Current liabilities:
Accounts payable and accrued liabilities	$ 198,068	$	147,187
Total current liabilities	198,068		147,187
Long-term debt	—		—
Other noncurrent liabilities
Payable to affiliate	352,306		294,858
Asset retirement obligations	13,008		13,008
Other	—		—
Stockholders’ equity:
Additional paid-in capital	617,631		561,834
Accumulated deficit	(46,185	)	(31,571	)
Total stockholders’ equity	571,446		530,263
Total liabilities and stockholders’ equity	$ 1,134,828	$	985,316

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The following table presents cash flow statement information for BHP Eagle Ford Gathering for the six months ended December 31, 2013 and 2012:

	Six months Ended December 31, — 2013		2012
Cash flows from operating activities:
Net loss	$ (14,613	)	$ (3,301	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depletion, depreciation and amortization	14,213		9,906
Income tax expense (benefit)	(312	)	(2,109	)
Other operating	—		1
Change in assets and liabilities:
Accounts receivable	16,246		(6,214	)
Prepaid and other	(6,933	)	77
Accounts payable and accrued liabilities	50,881		(13,037	)
Net cash (used in) provided by operating activities	59,482		(14,679	)
Cash flows from investing activities:
Other operating property and equipment capital expenditures	(184,263	)	(147,347	)
Net cash used in investing activities	(184,263	)	(147,347	)
Cash flows from financing activities:
Payable to affiliate	57,448		55,305
Net Contributions/Distributions from/to affiliate	55,797		74,902
Net cash provided by financing activities	113,245		130,207
Net increase (decrease) in cash	(11,536	)	(31,819	)
Cash at beginning of period	30,433		55,327
Cash at end of period	$ 18,897		$ 23,508

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. BHP Eagle Ford Gathering (formerly EagleHawk Field Services) , 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.

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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 six months ended December 31, 2013, were $252.7 million. For the six months ended December 31, 2013 and for unsettled prior period activity, $91.6 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 December 31, 2013, is $192.6 million.

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MANAGEMENT’S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS

The following discussion is intended to assist in understanding our results of operations for the six months ended December 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 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 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 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 engaged Scotia Waterous to advise on the possible divestment of certain land in the Permian, including acreage in both the Delaware and Midland Basins. No sale has yet been completed.

Portions of the Eagle Ford gathering line system have been temporarily isolated while the cause of potential corrosion issues is being analyzed. We are continuing to produce from this field and have increased the use of trucking to deliver our condensate to the market which is expected to mitigate any significant impact on production. Regulatory authorities have been notified.

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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.

Repayment of Long Term Debt

On January 2, 2014, the Company issued a formal notice of redemption to noteholders of its 10.5% Senior Notes due 2014 and 7.875% Senior Notes due 2015. All outstanding Senior Notes due 2014 and 2015 were redeemed on February 3, 2014 at the applicable call prices (see Note #3). The total aggregate principal value of the notes redeemed was approximately $1.4 billion US Dollars.

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Comparison of Results of Operations

Six months Ended December 31, 2013 Compared to Six months Ended December 31, 2012

We reported loss from continuing operations, net of income taxes, of $60.8 million for the six months ended December 31, 2013, compared to a loss from continuing operations, net of income taxes, of $72.7 million for the comparable period in 2012. The following table summarizes key items of comparison and their related change for the periods indicated.

(In thousands (except per unit and per Mcfe amounts))	Six months Ended December 31, — 2013		2012		Change
Income (loss) from continuing operations, net of income taxes	$ (60,765	)	$ (72,658	)	$ 11,893
Operating revenues:
Oil and natural gas	1,528,657		1,058,288		470,369
Marketing	224,412		7,451		216,961
Midstream	28,229		35,119		(6,890	)
Operating expenses:
Marketing	228,698		6,884		221,814
Production:
Lease operating	169,032		44,557		124,475
Workover and other	17,312		6,040		11,272
Taxes other than income	80,905		45,413		35,492
Gathering, transportation and other	254,253		158,450		95,803
General and administrative	146,271		80,833		65,438
Depletion, depreciation and amortization:
Depletion – Full cost	651,347		556,460		94,887
Depreciation – Midstream	18,393		18,260		133
Depreciation – Other	19,978		19,474		504
Rig contract termination costs	74,963		—		74,963
Accretion expense	4,066		1,200		2,866
Impairment of intangible asset	—		67,237		(67,237	)
Other income (expenses):
Net gain on derivative contracts	—		—		—
Interest expense and other	(212,469	)	(217,633	)	5,164
Income (loss) from continuing operations before income taxes	(96,389	)	(121,583	)	25,194
Income tax benefit (expense)	35,624		48,925		(13,301	)
Production:
Natural gas – Mmcf	145,666		138,164		7,502
Crude oil – MBbl	9,254		4,045		5,209
Natural gas liquids – MBbl	4,852		2,908		1,944
Natural gas equivalent – Mmcfe (1)	230,297		179,881		50,416
Average daily production – Mmcfe (1)	1,252		978		274
Average price per unit:
Natural gas price – Mcf	$ 3.41		$ 3.54		$ (0.13	)
Crude oil price – Bbl	96.37		111.63		(15.26	)
Natural gas liquids price – Bbl	29.17		35.78		(6.61	)
Natural gas equivalent price – Mcfe (1)	6.64		5.81		0.83
Average cost per Mcfe:
Production:
Lease operating	0.73		0.25		0.48
Workover and other	0.08		0.03		0.05
Taxes other than income	0.35		0.25		0.10
Gathering, transportation and other	1.10		0.88		0.22
General and administrative	0.64		0.45		0.19
Depletion ( excludes depreciation and amortization )	2.83		3.09		(0.26	)

(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.

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For the six months ended December 31, 2013, oil and natural gas revenues increased $470.4 million from the same period in 2012, to $1,529 million. The increase was primarily due to the increase in crude oil, natural gas liquids (NGLs) and natural gas volumes of 128.8%, 66.8% and 5.4%. The change in volumes added $677.6 million in revenue. Price movements negatively impacted revenues, with crude oil and natural gas falling $15.26 per barrel and $0.13 per mmcf, respectively. NGL prices dropped 18.5% or $6.61 to $29.17 per barrel versus $35.78 in the same period in 2012. The change in prices reduced revenue by $192.8 million. Other revenue dropped $14.5 million for the six months ended December 31, 2013 vs. December 31, 2012.

We had marketing revenues of $224.4 million and marketing expenses of $228.7 million for the six months ended December 31, 2013, resulting in a loss before income taxes of $4.3 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 $84.0 million for the six months ended December 31, 2013, compared to the same period in 2012 of $35.1 million, an increase of $48.9 million. The increase in gross revenues from our midstream business primarily relates to income for gathering services relating to new production and an increase in condensate handling fees due to additional volumes at Eagle Ford. In accordance with the financing method for a failed sale of in substance real estate we record BHP Eagle Ford Gathering revenues, net of eliminations for intercompany amounts associated with gathering and treating services provided to us on the consolidated statements of operations. For the six months ended June 30, 2013, approximately $28.2 million in revenues, after intercompany eliminations, from BHP Eagle Ford Gathering were reported in midstream revenues on the consolidated statements of operations.

Lease operating expenses increased $124.5 million for the six months ended December 31, 2013, as compared to the same period in 2012. The increase was primarily due to an increase in the number of wells put online, increased water handling costs combined with increased production. We continue to move towards higher liquids production versus gas production. The liquid volumes are more expensive to produce than gas volumes. On a per unit basis, lease operating expenses increased $0.48 per Mcfe to $0.73 per Mcfe in 2013 from $0.25 per Mcfe in 2012.

Taxes other than income increased $35.5 million for the six months ended December 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 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 six months ended December 31, 2013, we recorded severance tax refunds totaling $11.3 million compared to $3.9 million in the prior year. On a per unit basis, excluding the severance tax refunds, taxes other than income were $0.40 per Mcfe in 2013 compared to $0.27 per Mcfe in 2012.

Gathering, transportation and other expense increased $95.8 million for the six months ended December 31, 2013 as compared to the same period in 2012. On a per unit basis, gathering transportation and other increased $0.22 per Mcfe from $0.88 per Mcfe in 2012 to $1.10 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 six month period, the Company continued to make modifications to the number of rigs within our rig fleet. As such, for the six months ended December 31, 2013, we incurred costs of approximately $75.0 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 $65.4 million for the six months ended December 31, 2013 as compared to the same period in 2012. On a per unit basis this represents an increase of $0.19 per Mcfe, from $0.45 per Mcfe to $0.64 per Mcfe. This was caused by an increase to headcount and support activity for our operations since the previous year.

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 $94.9 million for the six months ended December 31, 2013, from the same period in 2012, to $651.3 million primarily due to increased production. On a per unit basis, depletion expense decreased $0.26 per Mcfe to $2.83 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 six months ended December 31, 2013.

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Depreciation expense associated with our gas gathering systems increased $0.1 million to $18.4 million for the six months ended December 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. Depreciation expense associated with our other operating property and equipment increased $0.5 million to $20.0 million for the six months ended December 31, 2013, as compared to the same period in 2012.

Interest expense and other decreased $5.2 million for the six months ended December 31, 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 BHP Eagle Ford Gathering joint venture under the financing method for a failed sale of in substance real estate. For the six months ended December 31, 2013, we recorded approximately $81.9 million of interest expense on the financing obligations compared to $83.0 million in the prior year.

We had an income tax benefit of $35.6 million for the six months ended December 31, 2013, due to our loss from operations before income taxes of $96.4 million compared to an income tax benefit of $48.9 million due to our loss from operations before income taxes of $121.6 million in the prior year. The effective tax rate for the six months ended December 31, 2013, was 37.0% compared to 40.2% for the six months ended December 31, 2012.

Investment in BHP Eagle Ford Gathering (formerly Investment in EagleHawk)

BHP Eagle Ford Gathering had gross revenues of $52.8 million related to its Eagle Ford Shale gathering and treating systems in the Hawkville and Black Hawk Fields for the six months ended December 31, 2013, compared to $50.1 million for the six months ended December 31, 2012. Gross revenues include $24.6 million and $21.1 million of intercompany revenues that were eliminated in consolidation for the six months ended December 31, 2013 and 2012, respectively. Total operating expenses for BHP Eagle Ford Gathering for the six months ended December 31, 2013, of $37.2 million included $18.3 million in gathering, transportation and other expenses and $15.7 million in depreciation expense. Total operating expenses for the six months ended December 31, 2012 of $25.2 million included $12.1 million in gathering, transportation and other expenses and $9.9 million in depreciation expense. Gathering, transportation and other expenses for BHP Eagle Ford Gathering consist of costs to operate the pipelines, such as treating, processing, measuring and transporting expenses. Depreciation expense on BHP Eagle Ford Gathering’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.

By:	BHP Billiton Limited and BHP Billiton Plc — /s/ Jane McAloon
Name:	Jane McAloon
Title:	Group Company Secretary