Edgar Filing: PETROHAWK ENERGY CORP

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2011

Commission file number 001-33334

PETROHAWK ENERGY CORPORATION
(Exact name of registrant as specified in its charter)


Delaware (State or other jurisdiction of incorporation or organization)		86-0876964 (I.R.S. Employer Identification Number)
1000 Louisiana, Suite 5600, Houston, Texas 77002 (Address of principal executive offices including ZIP code)

(832) 204-2700
(Registrant's telephone number)

Securities registered pursuant to Section 12(b) of the Act:

Title of each class		Name of each exchange on which registered

Common Stock, par value $.001 per share		New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of "large accelerated filer", "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act:


Large accelerated filer ý		Accelerated filer o		Non-accelerated filer o (Do not check if a smaller reporting company)		Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No ý

As of July 28, 2011 the Registrant had 303,893,547 shares of Common Stock, $.001 par value, outstanding.

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PART I. FINANCIAL INFORMATION
	ITEM 1.	Condensed consolidated financial statements (unaudited)	5
		Condensed consolidated statements of operations for the three and six months ended June 30, 2011 and 2010	5
		Condensed consolidated balance sheets as of June 30, 2011 and December 31, 2010	6
		Condensed consolidated statements of cash flows for the six months ended June 30, 2011 and 2010	7
		Notes to condensed consolidated financial statements	8
	ITEM 2.	Management's discussion and analysis of financial condition and results of operations	39
	ITEM 3.	Quantitative and qualitative disclosures about market risk	56
	ITEM 4.	Controls and procedures	58
PART II. OTHER INFORMATION
	ITEM 1.	Legal proceedings	58
	ITEM 1A.	Risk factors	59
	ITEM 2.	Unregistered sales of equity securities and use of proceeds	62
	ITEM 3.	Defaults upon senior securities	62
	ITEM 4.	(Removed and reserved)	62
	ITEM 5.	Other information	62
	ITEM 6.	Exhibits	63

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Special note regarding forward-looking statements

This Quarterly Report on Form 10-Q contains, and we may from time to time otherwise make in other public filings, press releases and presentations, forward-looking statements within the meaning of the federal securities laws. All statements, other than statements of historical facts, concerning, among other things, planned capital expenditures, potential increases in oil and natural gas production, the number and location of wells to be drilled in the future, future cash flows and borrowings, pursuit of potential acquisition opportunities, our financial position, business strategy and other plans and objectives for future operations, are forward-looking statements. These forward- looking statements are identified by their use of terms and phrases such as "may," "expect," "estimate," "project," "plan," "believe," "intend," "achievable," "anticipate," "will," "continue," "potential," "should," "could" and similar terms and phrases. Although we believe that the expectations reflected in these forward-looking statements are reasonable, they do involve certain assumptions, risks and uncertainties. Actual results could differ materially from those anticipated in these forward-looking statements. One should consider carefully the statements under the "Risk Factors" section of this report and in our Annual Report on Form 10-K for the year ended December 31, 2010 and the other disclosures contained herein and therein, which describe factors that could cause our actual results to differ from those anticipated in the forward-looking statements, including, but not limited to, the following factors:

•: our ability to successfully develop our large inventory of undeveloped acreage in our resource plays such as the Haynesville, Lower Bossier, and Eagle Ford Shales;
•: volatility in commodity prices for oil and natural gas;
•: the possibility that our industry may be subject to future regulatory or legislative actions (including any additional taxes and changes in environmental regulation);
•: the presence or recoverability of estimated oil and natural gas reserves and the actual future production rates and associated costs;
•: the potential for production decline rates for our wells to be greater than we expect;
•: our ability to generate sufficient cash flow from operations, borrowings or other sources to enable us to fully develop our undeveloped acreage positions;
•: our ability to replace oil and natural gas reserves;
•: environmental risks;
•: drilling and operating risks;
•: exploration and development risks;
•: competition, including competition for acreage in resource play areas;
•: management's ability to execute our plans to meet our goals;
•: our ability to retain key members of senior management and key technical employees especially given the pending merger with affiliates of BHP Billiton Limited;
•: the cost and availability of goods and services, such as drilling rigs, fracture stimulation services and tubulars;
•: access to and availability of water and other treatment materials to carry out planned fracture stimulations in our resource plays;
•: access to adequate gathering systems and transportation take-away capacity, necessary to fully execute our capital program;

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•: our ability to secure firm transportation and other marketing outlets for the natural gas, natural gas liquids and crude oil and condensate we produce and to sell these products at market prices;
•: the possibility that our merger with affiliates of BHP Billiton Limited could not be completed or could be delayed, which could negatively affect our stock price and our future business, operations and financial results;
•: general economic conditions, whether internationally, nationally or in the regional and local market areas in which we do business, may be less favorable than expected, including the possibility that the economic conditions in the United States will worsen and that capital markets are disrupted, which could adversely affect demand for oil and natural gas and make it difficult to access financial markets;
•: social unrest, political instability, armed conflict, or acts of terrorism or sabotage in oil and natural gas producing regions, such as the Middle East, or our markets; and
•: other economic, competitive, governmental, legislative, regulatory, geopolitical and technological factors that may negatively impact our business, operations or pricing.

All forward-looking statements are expressly qualified in their entirety by the cautionary statements in this paragraph and elsewhere in this document. Other than as required under the securities laws, we do not assume a duty to update these forward-looking statements, whether as a result of new information, subsequent events or circumstances, changes in expectations or otherwise.

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PART I. FINANCIAL INFORMATION

Item 1. Condensed Consolidated Financial Statements (Unaudited)

PETROHAWK ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(In thousands, except per share amounts)

				Three Months Ended June 30,						Six Months Ended June 30,

				2011			2010			2011			2010
Operating revenues:
	Oil and natural gas			$	443,729		$	239,834		$	793,937		$	540,425
	Marketing				149,486			107,338			290,030			237,457
	Midstream				1,865			3,954			2,837			11,026

		Total operating revenues			595,080			351,126			1,086,804			788,908

Operating expenses:
	Marketing				161,049			117,309			315,947			253,931
	Production:
			Lease operating		13,726			16,384			26,337			33,779
			Workover and other		4,308			1,571			9,184			3,949
	Taxes other than income				16,779			5,111			28,514			17,871
	Gathering, transportation and other				66,901			33,299			119,796			61,455
	General and administrative				50,302			43,100			90,277			75,134
	Depletion, depreciation and amortization				192,808			99,855			350,120			204,623

			Total operating expenses		505,873			316,629			940,175			650,742
Amortization of deferred gain					46,508			64,367			94,976			64,367

Income from operations					135,715			98,864			241,605			202,533
Other income (expenses):
	Net gain (loss) on derivative contracts				83,507			(16,625	)		32,600			198,078
	Interest expense and other				(67,019	)		(61,533	)		(133,822	)		(124,379	)
	Equity investment income				17,339			2,047			30,910			2,047

			Total other income (expenses)		33,827			(76,111	)		(70,312	)		75,746

Income from continuing operations before income taxes					169,542			22,753			171,293			278,279
Income tax provision					(64,660	)		(8,741	)		(65,231	)		(107,975	)

Income from continuing operations, net of income taxes					104,882			14,012			106,062			170,304
Loss from discontinued operations, net of income taxes					(753	)		(517	)		(3,161	)		(674	)

Net income				$	104,129		$	13,495		$	102,901		$	169,630

Net income (loss) per share:
	Basic:
			Continuing operations	$	0.35		$	0.05		$	0.35		$	0.57
			Discontinued operations		—			(0.01	)		(0.01	)		(0.01	)

			Total	$	0.35		$	0.04		$	0.34		$	0.56

	Diluted:
			Continuing operations	$	0.34		$	0.05		$	0.35		$	0.56
			Discontinued operations		—			(0.01	)		(0.01	)		—

			Total	$	0.34		$	0.04		$	0.34		$	0.56

Weighted average shares outstanding:
	Basic				301,603			300,426			301,321			300,292

	Diluted				305,464			302,446			305,101			302,715

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

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PETROHAWK ENERGY CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)

(In thousands, except share and per share amounts)

			June 30, 2011			December 31, 2010

Current assets:
	Cash		$	1,655		$	1,591
	Accounts receivable			468,270			356,597
	Receivables from derivative contracts			154,308			217,018
	Prepaids and other			50,054			62,831

		Total current assets		674,287			638,037

Oil and natural gas properties (full cost method):
	Evaluated			9,152,679			7,520,446
	Unevaluated			2,494,353			2,387,037

		Gross oil and natural gas properties		11,647,032			9,907,483
	Less—accumulated depletion			(5,117,172	)		(4,774,579	)

		Net oil and natural gas properties		6,529,860			5,132,904

Other operating property and equipment:
	Gas gathering systems and equipment			280,858			150,372
	Other operating assets			71,021			55,315

		Gross other operating property and equipment		351,879			205,687
	Less—accumulated depreciation			(25,757	)		(19,194	)

		Net other operating property and equipment		326,122			186,493

Other noncurrent assets:
	Goodwill			932,802			932,802
	Other intangible assets, net of amortization			83,816			89,342
	Debt issuance costs, net of amortization			64,926			45,941
	Deferred income taxes			173,617			258,570
	Receivables from derivative contracts			38,605			41,721
	Assets held for sale			—			74,448
	Equity investment			211,990			217,240
	Other			4,608			6,944

Total assets			$	9,040,633		$	7,624,442

Current liabilities:
	Accounts payable and accrued liabilities		$	1,032,375		$	787,238
	Deferred income taxes			17,503			48,499
	Liabilities from derivative contracts			16,101			5,820
	Payable to equity affiliate			600			976
	Long-term debt			15,556			14,790

		Total current liabilities		1,082,135			857,323

Long-term debt				3,766,380			2,612,852
Other noncurrent liabilities:
	Liabilities from derivative contracts			14,789			13,575
	Asset retirement obligations			38,923			31,741
	Deferred gain on sale			469,145			564,121
	Other			604			544
	Commitments and contingencies (Note 7)
Stockholders' equity:
	Common stock: 500,000,000 shares of $.001 par value authorized; 303,896,636 and 302,489,501 shares issued and outstanding at June 30, 2011 and December 31, 2010, respectively			304			302
	Additional paid-in capital			4,653,077			4,631,609
	Accumulated deficit			(984,724	)		(1,087,625	)

		Total stockholders' equity		3,668,657			3,544,286

Total liabilities and stockholders' equity			$	9,040,633		$	7,624,442

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

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PETROHAWK ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(In thousands)

		Six Months Ended June 30,

		2011			2010
Cash flows from operating activities:
Net income		$	102,901		$	169,630
Adjustments to reconcile net income to net cash provided by operating activities:
	Depletion, depreciation and amortization		350,120			207,249
	Income tax provision		63,280			107,561
	Loss on sale		3,950			—
	Stock-based compensation		14,300			10,397
	Net unrealized loss (gain) on derivative contracts		83,909			(102,671	)
	Amortization of deferred gain		(94,976	)		(64,367	)
	Equity investment income		(30,910	)		(2,047	)
	Distributions from equity affiliate		36,160			4,236
	Other operating		18,914			16,757
Change in assets and liabilities:
	Accounts receivable		(120,801	)		(27,025	)
	Prepaids and other		12,777			(18,538	)
	Accounts payable and accrued liabilities		98,190			14,075
	Payable to equity affiliate		(376	)		(12,885	)
	Other		2,593			17,154

Net cash provided by operating activities			540,031			319,526

Cash flows from investing activities:
	Oil and natural gas capital expenditures		(1,674,519	)		(1,206,288	)
	Proceeds received from sale of oil and natural gas properties		76,109			491,094
	Proceeds received from the contribution of Haynesville gas gathering systems		—			921,408
	Proceeds received from sale of Fayetteville gas gathering systems		76,898			—
	Marketable securities purchased		(330,000	)		(978,006	)
	Marketable securities redeemed		330,000			697,000
	Increase in restricted cash		(295,748	)		(75,005	)
	Decrease in restricted cash		295,748			231,523
	Other operating property and equipment capital expenditures		(134,653	)		(173,840	)

Net cash used in investing activities			(1,656,165	)		(92,114	)

Cash flows from financing activities:
	Proceeds from exercise of stock options		4,941			1,276
	Proceeds from borrowings		3,679,500			942,000
	Repayment of borrowings		(2,539,262	)		(1,165,780	)
	Debt issuance costs		(24,861	)		(704	)
	Other		(4,120	)		(3,573	)

Net cash provided by (used in) financing activities			1,116,198			(226,781	)

Net increase in cash			64			631
Cash at beginning of period			1,591			1,511

Cash at end of period		$	1,655		$	2,142

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

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PETROHAWK ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

1. FINANCIAL STATEMENT PRESENTATION

Petrohawk Energy Corporation (Petrohawk or the Company) is an independent oil and natural gas company engaged in the exploration, development and production of predominately natural gas properties located in the United States. The Company operates in two segments, oil and natural gas production and midstream operations. The unaudited condensed consolidated financial statements include the accounts of all majority-owned, controlled subsidiaries. The Company uses the equity method to account for investments in which the Company does not have a majority interest, but does have significant influence. All intercompany accounts and transactions have been eliminated. Certain prior year amounts have been reclassified to conform to the current year presentation. These unaudited condensed consolidated financial statements reflect, in the opinion of the Company's management, all adjustments, consisting only of normal and recurring adjustments, necessary to present fairly the financial position as of, and the results of operations for, the periods presented. During interim periods, Petrohawk follows the accounting policies disclosed in its 2010 Annual Report on Form 10-K, filed with the United States Securities and Exchange Commission (SEC). Please refer to the footnotes in the 2010 Annual Report on Form 10-K when reviewing interim financial results.

Use of Estimates

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

Interim period results are not necessarily indicative of results of operations or cash flows for the full year and accordingly, certain information normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States has been condensed or omitted. The Company has evaluated events or transactions through the date of issuance of these unaudited condensed consolidated financial statements.

Marketing Revenue and Expense

A subsidiary of the Company purchases and sells the Company's own and third party natural gas produced from wells which the Company and third parties operate. The revenues and expenses related to these marketing activities are reported on a gross basis as part of operating revenues and operating expenses. Marketing revenues are recorded at the time natural gas is physically delivered to third parties at a fixed or index price. Marketing expenses attributable to gas purchases are recorded as the Company takes physical title to natural gas and transports the purchased volumes to the point of sale.

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PETROHAWK ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited) (Continued)

1. FINANCIAL STATEMENT PRESENTATION (Continued)

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 midstream operations segment 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.

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 capitalized $1.0 million and $1.7 million of interest for the three and six months ended June 30, 2011, respectively, and $1.3 million and $2.5 million of interest for the three and six months ended June 30, 2010, respectively, related to the construction of the Company's gas gathering systems and equipment.

Gas gathering systems and equipment as of June 30, 2011 and December 31, 2010 consisted of the following:

		June 30, 2011			December 31, 2010⁽¹⁾

		(In thousands)
Gas gathering systems and equipment		$	280,858		$	305,096
Less—accumulated depreciation			(5,661	)		(13,729	)

	Net gas gathering systems and equipment	$	275,197		$	291,367

(1): Includes gas gathering systems and equipment of approximately $155 million and related accumulated depreciation of approximately $11 million associated with the Company's Fayetteville Shale midstream assets, which were classified as "Assets held for sale" in the unaudited condensed consolidated balance sheet at December 31, 2010. "Assets held for sale" were recorded at the lesser of the carrying amount or the fair value less costs to sell, which resulted in a write down of approximately $69.7 million that was recorded in the year ended December 31, 2010. "Assets held for sale" were approximately $74 million as of December 31, 2010. The Company divested its Fayetteville Shale midstream operations on January 7, 2011.

Other operating property and equipment are recorded at cost. Depreciation is calculated using the straight-line method. Upon disposition, the cost and accumulated depreciation are removed and any gains or losses are reflected in current operations. Maintenance and repair costs are charged to operating expense as incurred. Material expenditures which increase the life of an asset are capitalized and depreciated over the estimated remaining useful life of the asset.

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PETROHAWK ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited) (Continued)

1. FINANCIAL STATEMENT PRESENTATION (Continued)

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.

Equity Method Investment

On May 21, 2010, the Company contributed its Haynesville Shale gas gathering and treating business in exchange for a 50% membership interest in a joint venture entity, KinderHawk Field Services LLC (KinderHawk), and approximately $917 million in cash. The Company's investment in KinderHawk, in which the Company did not have a majority interest, but did have significant influence, has been accounted for under the equity method of accounting. Under the equity method of accounting, the Company's share of net income (loss) from KinderHawk is reflected as an increase (decrease) in its investment account in "Other noncurrent assets" and is also recorded as "Equity investment income" in "Other income (expenses)." Distributions from KinderHawk are recorded as reductions of the Company's investment and contributions to KinderHawk are recorded as increases of the Company's investment. The Company reviews equity method investments for potential impairment whenever events or changes in circumstances indicate that an other-than-temporary decline in the value of the investment has occurred. See Note 13, "Equity Method Investment," for further discussion. On July 1, 2011, the Company sold its remaining 50% membership interest in KinderHawk. See Note 15, "Subsequent Events," for additional details of this transaction.

Amortization of Deferred Gain

On May 21, 2010, the Company contributed its Haynesville Shale gathering and treating business in Northwest Louisiana to KinderHawk and KM Gathering LLC (KM Gathering), an affiliate of Kinder Morgan Energy Partners, L.P. (Kinder Morgan), a publicly traded master limited partnership, contributed approximately $917 million ($875 million for a 50% membership interest in KinderHawk and $42 million for certain closing adjustments, including 2010 capital expenditures through the closing date) in cash to KinderHawk, which was distributed to the Company. At May 21, 2010, as a result of the transaction, the Company recorded a deferred gain of approximately $719.4 million for the difference between 50% of the net carrying value of the assets it contributed to the joint venture and the net cash proceeds from KinderHawk, representing the cash contributed by Kinder Morgan at closing for its 50% membership interest in KinderHawk. The Company recognizes the portion of the deferred gain equal to its capital commitment as contributions to KinderHawk are made or upon expiration of the capital commitment at December 31, 2011. On July 1, 2011, in conjunction with the closing of the Company's sale of its remaining 50% membership interest in KinderHawk, the balance of the Company's capital commitment to KinderHawk was relieved and the applicable portion of the deferred gain equal to its remaining capital commitment will be recognized in the third quarter of 2011. See Note 15, "Subsequent Events" for more details. In addition to the capital commitment, the Company guaranteed to deliver certain minimum annual volumes of natural gas through the

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PETROHAWK ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited) (Continued)

1. FINANCIAL STATEMENT PRESENTATION (Continued)

Haynesville gathering system through May 2015. The Company recognizes the remaining portion of the deferred gain recorded in the transaction as volumes are delivered through the Haynesville gathering system through May 2015. The Company's obligation to deliver minimum annual volumes of natural gas to KinderHawk through May 2015 remains in effect following the sale of the Company's remaining 50% membership interest in KinderHawk on July 1, 2011, and the Company will continue to recognize the deferred gain associated with the delivered volumes through May 2015. The recognition of the deferred gain is included in "Amortization of deferred gain" in the unaudited condensed consolidated statements of operations.

Goodwill

Goodwill represents the excess of the purchase price over the estimated fair value of the assets acquired net of the fair value of liabilities assumed in an acquisition. ASC 350, Intangibles—Goodwill and Other (ASC 350) requires that intangible assets with indefinite lives, including goodwill, be evaluated on an annual basis for impairment or more frequently if events occur or circumstances change that could potentially result in impairment. The goodwill impairment test requires the allocation of goodwill and all other assets and liabilities to reporting units. The Company has determined that it has two reporting units: oil and natural gas production and midstream operations. All of the Company's goodwill has been allocated to its oil and natural gas production reporting unit as all of its historical goodwill relates to its acquisitions of oil and natural gas properties. The Company performs its goodwill test annually during the third quarter, or more often if circumstances require.

Other Intangible Assets

The Company treats the costs associated with acquired transportation contracts as other intangible assets. The initial amount recorded represents the fair value of the contract at the time of acquisition, which is amortized using the straight-line method over the life of the contract. Any unamortized balance of the Company's other intangible assets is subject to impairment testing pursuant to the Impairment or Disposal of Long-Lived Assets Subsections of ASC Subtopic 360-10. 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.

Amortization expense was $2.8 million and $5.5 million for the three and six months ended June 30, 2011, respectively, and $2.8 million and $5.5 million for the three and six months ended June 30, 2010, respectively, and was allocated to operating expenses between "Marketing" and "Gathering, transportation and other" on the unaudited condensed consolidated statements of operations based on the usage of the contract. The estimated amortization expense will be approximately $11.1 million per year for the remainder of the contract through 2019.

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PETROHAWK ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited) (Continued)

1. FINANCIAL STATEMENT PRESENTATION (Continued)

Other intangible assets subject to amortization at June 30, 2011 and December 31, 2010 are as follows:

		June 30, 2011			December 31, 2010

		(In thousands)
Transportation contracts		$	105,108		$	105,108
Less—accumulated amortization			(21,292	)		(15,766	)

	Net transportation contracts	$	83,816		$	89,342

Assets Held for Sale

As discussed in Note 2, "Acquisitions and Divestitures," the Company divested its Fayetteville Shale midstream operations on January 7, 2011 for approximately $75 million in cash, before customary closing adjustments. The Company's assets related to the Fayetteville Shale midstream operations were presented separately as "Assets held for sale" in the unaudited condensed consolidated balance sheet at December 31, 2010, in accordance with ASC 360. Assets held for sale were recorded at the lesser of the carrying amount or the fair value less costs to sell, which resulted in a write down of the carrying amount of approximately $69.7 million that was recorded in the year ended December 31, 2010.

Discontinued Operations

Certain amounts related to the Company's Fayetteville Shale midstream operations and other operating property and equipment have been reclassified to discontinued operations for all periods presented. Unless otherwise noted, information contained in the notes to the unaudited condensed consolidated financial statements relates to the Company's continuing operations. See Note 14, "Discontinued Operations," for further discussion of the presentation of the Company's Fayetteville Shale midstream and other operating assets as discontinued operations.

Recently Issued Accounting Pronouncements

In December 2010, the FASB issued Accounting Standards Update (ASU) No. 2010-28, When to Perform Step 2 of the Goodwill Impairment Test for Reporting Units with Zero or Negative Carrying Amounts (ASU 2010-28). This codification update modifies Step 1 of the goodwill impairment test for reporting units with zero or negative carrying amounts and requires reporting units with such carrying amounts to perform Step 2 of the goodwill impairment test if it is more likely than not that a goodwill impairment exists. ASU 2010-28 is effective for fiscal years and interim periods beginning after December 15, 2010 and early adoption is not permitted. The Company adopted the provisions of this update in the first quarter of 2011 and will apply the provisions of ASU 2010-28 when the Company's annual goodwill test is performed in 2011. The Company does not expect a material impact on its operating results, financial position, cash flows or disclosures as a result of the adoption.

In December 2010, the FASB issued ASU No. 2010-29, Disclosure of Supplementary Pro Forma Information for Business Combinations (ASU 2010-29). ASU 2010-29 requires a public entity who discloses comparative pro forma information for business combinations that occurred in the current reporting period to disclose revenue and earnings of the combined entity as though the business combination(s) occurred as of the beginning of the comparable prior annual period only. This update

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1. FINANCIAL STATEMENT PRESENTATION (Continued)

also expands the supplemental pro forma disclosures required to include a description of the nature and amount of material, nonrecurring pro forma adjustments directly attributable to the business combination included in the reported pro forma revenue and earnings. ASU 2010-29 is effective for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2010 and early adoption is permitted. The Company will apply the provisions of this update for any business combinations that occur after January 1, 2011.

In May 2011, the FASB issued ASU No. 2011-04, Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs (ASU 2011-04). The amendments in ASU 2011-04 are the result of the FASB's and the International Accounting Standards Board's (IASB) work to develop common requirements for measuring fair value and for disclosing information about fair value measurements in accordance with generally accepted accounting principles (GAAP) in the United States and the International Financial Reporting Standards (IFRS). ASU 2011-04 explains how to measure fair value and changes the wording used to describe many of the fair value requirements in GAAP, but does not require additional fair value measurements. The amendments in this update are to be applied prospectively to interim and annual reporting periods beginning after December 15, 2011. The Company is currently assessing the impact that the adoption of ASU 2011-04 will have on its operating results, financial position, cash flows and disclosures.

2. ACQUISITIONS AND DIVESTITURES

Divestitures

Fayetteville Shale

On December 22, 2010, the Company completed the sale of its interest in natural gas properties and related other operating property and equipment in the Fayetteville Shale for $575 million in cash, before customary closing adjustments. Proceeds from the sale of the interest in natural gas properties were recorded as a reduction to the carrying value of the Company's full cost pool with no gain or loss recorded. In conjunction with the sale of the related other operating property and equipment, the Company recorded a loss of approximately $0.5 million in the year ended December 31, 2010. On January 7, 2011, the Company completed the sale of its midstream assets in the Fayetteville Shale for approximately $75 million in cash, before customary closing adjustments. As of December 31, 2010, the Fayetteville Shale midstream assets were classified as "Assets held for sale" on the Company's unaudited condensed consolidated balance sheet. "Assets held for sale" were recorded at the lesser of the carrying amount or the fair value less costs to sell, which resulted in a write down of the carrying amount of approximately $69.7 million in the year ended December 31, 2010. Both transactions had an effective date of October 1, 2010.

Mid-Continent Properties

On September 29, 2010, the Company completed the sale of its interest in certain oil and natural gas properties in Texas, Oklahoma and Arkansas for $123 million in cash, before customary closing adjustments. Proceeds from the sale were recorded as a reduction to the carrying value of the Company's full cost pool with no gain or loss recorded. The transaction had an effective date of July 1, 2010.

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2. ACQUISITIONS AND DIVESTITURES (Continued)

Hawk Field Services, LLC Joint Venture

On May 21, 2010, Hawk Field Services, LLC (Hawk Field Services), a wholly owned subsidiary of Petrohawk, and Kinder Morgan formed a new joint venture pursuant to a Formation and Contribution Agreement (Contribution Agreement). The new joint venture entity, KinderHawk, engages in the natural gas midstream business in Northwest Louisiana, focused on the Haynesville and Lower Bossier Shales. Pursuant to the Contribution Agreement, Hawk Field Services contributed to KinderHawk its Haynesville Shale gathering and treating business in Northwest Louisiana, and Kinder Morgan contributed approximately $917 million in cash ($875 million for a 50% membership interest in KinderHawk and $42 million for certain closing adjustments including 2010 capital expenditures through the closing date) to KinderHawk. Each of Hawk Field Services and Kinder Morgan own a 50% membership interest in KinderHawk. KinderHawk distributed approximately $917 million to Hawk Field Services. The joint venture had an economic effective date of January 1, 2010, and Hawk Field Services continued to operate the business until September 30, 2010, at which date Hawk Field Services and Kinder Morgan terminated the transition services agreement and KinderHawk assumed operations of the joint venture. The Company accounts for its interest in KinderHawk under the equity method of accounting.

On July 1, 2011, the Company sold its remaining 50% membership interest in KinderHawk to Kinder Morgan. See Note 15, "Subsequent Events," for further discussion.

The Company is obligated to deliver to KinderHawk agreed upon minimum annual quantities of natural gas from Petrohawk operated wells producing from the Haynesville and Lower Bossier Shales with specified acreage in Northwest Louisiana through May 2015, or in the alternative, pay an annual true-up fee to KinderHawk if such minimum annual quantities are not delivered. The Company pays KinderHawk negotiated gathering and treating fees, subject to an annual inflation adjustment factor. The gathering fee is equal to $0.34 per thousand cubic feet (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. KinderHawk charges included in "Gathering, transportation and other" in the unaudited condensed consolidated statements of operations totaled approximately $30 million and $57 million for the three and six months ended June 30, 2011 and $8 million for the three and six months ended June 30, 2010, respectively. The Company's obligation to deliver minimum annual volumes of natural gas to KinderHawk through May 2015 remains in effect following the sale of the Company's remaining 50% membership interest in KinderHawk on July 1, 2011.

Terryville

On May 12, 2010, the Company completed the sale of its interest in Terryville Field, located in Lincoln and Claiborne Parishes, Louisiana for $320 million in cash, before customary closing adjustments. Proceeds from the sale were recorded as a reduction to the carrying value of the Company's full cost pool with no gain or loss recorded. The transaction had an effective date of January 1, 2010. In conjunction with the closing, the Company deposited $75 million with a qualified intermediary to facilitate like-kind exchange transactions all of which had been utilized as of December 31, 2010.

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2. ACQUISITIONS AND DIVESTITURES (Continued)

West Edmond Hunton Lime Unit

On April 30, 2010, the Company completed the sale of its interest in the West Edmond Hunton Lime Unit (WEHLU) Field in Oklahoma County, Oklahoma for $155 million in cash, before customary closing adjustments. Proceeds from the sale were recorded as a reduction to the carrying value of the Company's full cost pool with no gain or loss recorded. The transaction had an effective date of April 1, 2010.

3. OIL AND NATURAL GAS PROPERTIES

The Company uses the full cost method of accounting for its investment in oil and natural gas properties. Under this method of accounting, all costs of acquisition, exploration and development of oil and natural gas reserves (including such costs as leasehold acquisition costs, geological expenditures, dry hole costs, tangible and intangible development costs and direct internal costs) are capitalized as the cost of oil and natural gas properties when incurred. To the extent capitalized costs of evaluated oil and natural gas properties, net of accumulated depletion exceed the discounted future net revenues of proved oil and natural gas reserves net of deferred taxes, such excess capitalized costs are charged to expense. The Company uses the unweighted arithmetic average first day of the month price for oil and natural gas for the 12-month period preceding the calculation date to calculate the future net revenues of proved reserves.

The Company assesses all items classified as unevaluated property on a quarterly basis for possible impairment or reduction in value. The Company assesses properties on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of the following factors, among others: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization.

At June 30, 2011, the ceiling test value of the Company's reserves was calculated based on the first day average of the 12-months ended June 30, 2011 of the West Texas Intermediate (WTI) spot price of $90.90 per barrel, adjusted by lease or field for quality, transportation fees, and regional price differentials, and the first day average of the 12-months ended June 30, 2011 of the Henry Hub price of $4.21 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, 2011 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, 2010, the ceiling test value of the Company's reserves was calculated based on the first day average of the 12-months ended June 30, 2010 of the WTI posted price of $75.61 per barrel, adjusted by lease or field for quality, transportation fees, and regional price differentials, and the first day average of the 12-months ended June 30, 2010 of the Henry Hub price of $4.10 per Mmbtu, adjusted by lease or field for energy content, transportation fees, and regional price differentials. Using these prices, the Company's net book value of oil and natural gas properties at June 30, 2010 did not exceed the ceiling amount.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited) (Continued)

4. LONG-TERM DEBT

Long-term debt as of June 30, 2011 and December 31, 2010 consisted of the following:

	June 30, 2011⁽¹⁾		December 31, 2010⁽¹⁾

	(In thousands)
Senior revolving credit facility	$	559,000	$	146,000
6.25% $600 million senior notes⁽²⁾		600,000		—
7.25% $1.2 billion senior notes⁽³⁾		1,232,178		825,000
10.5% $600 million senior notes⁽⁴⁾		566,453		562,115
7.875% $800 million senior notes		800,000		800,000
7.125% $275 million senior notes⁽⁵⁾		—		268,922
Deferred premiums on derivatives		8,749		10,815

	$	3,766,380	$	2,612,852

(1): Table excludes $15.6 million and $14.6 million of deferred premiums on derivative contracts which have been classified as current at June 30, 2011 and December 31, 2010, respectively. Table also excludes $0.2 million of 9.875% senior notes due 2011 which were classified as current at December 31, 2010.
(2): On May 20, 2011, the Company issued $600 million principal amount of its 6.25% senior notes due 2019. See "6.25% Senior Notes" below for more details.
(3): On August 17, 2010 and January 31, 2011, the Company issued an initial $825 million principal amount and an additional $400 million principal amount, respectively, of its 7.25% senior notes due 2018. Amount includes a $7.2 million premium at June 30, 2011, 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.
(4): Amount includes a $33.6 million and $37.9 million discount at June 30, 2011 and December 31, 2010, respectively, 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.
(5): The 7.125% $275 million senior notes were redeemed during the first quarter of 2011. Amount includes a $3.5 million discount at December 31, 2010, recorded by the Company in conjunction with the assumption of the notes. See "7.125% Senior Notes" below for more details.

Senior Revolving Credit Facility

Effective August 2, 2010, the Company amended and restated its existing credit facility dated October 14, 2009 by entering into the Fifth Amended and Restated Senior Revolving Credit Agreement (the Senior Credit Agreement), among the Company, each of the lenders from time to time party thereto (the Lenders), BNP Paribas, as administrative agent for the Lenders, Bank of America, N.A. and Bank of Montreal as co-syndication agents for the Lenders, and JPMorgan Chase Bank, N.A. and Wells Fargo Bank, N.A., as co-documentation agents for the Lenders. On April 29, 2011, the Company entered into the Third Amendment to the Senior Credit Agreement. The Senior Credit Agreement

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4. LONG-TERM DEBT (Continued)

provides for a $2.5 billion facility. As of June 30, 2011, the borrowing base was approximately $1.9 billion, $1.8 billion of which related to the Company's oil and natural gas properties and up to $100 million (currently limited as described below) related to the Company's midstream assets. The portion of the borrowing base relating to the Company's oil and natural gas properties is redetermined on a semi-annual basis (with the Company and the Lenders each having the right to one annual interim unscheduled redetermination) and adjusted based on the Company's oil and natural gas properties, reserves, other indebtedness and other relevant factors. The component of the borrowing base relating to the Company's midstream assets is limited to the lesser of $100 million or 3.5 times midstream earnings before interest, taxes, depreciation and amortization (EBITDA), and is calculated quarterly. As of June 30, 2011, the full capacity of the midstream component of the borrowing base was available. At June 30, 2011, the Company had approximately $34.7 million outstanding letters of credit with various customers, vendors and others. The Company's borrowing base is subject to a reduction equal to the product of $0.25 multiplied by the stated principal amount (without regard to any initial issue discount) of any unsecured senior or senior subordinated notes that the Company may issue. In connection with the issuance of the Company's 6.25% $600 million senior notes due 2019, as described below, the lenders under the Senior Credit Agreement waived the automatic reduction in the Company's borrowing base. As a result, the Company's borrowing base under the Senior Credit Agreement remained at $1.9 billion upon the issuance of the 6.25% $600 million senior notes due 2019.

Amounts outstanding under the Senior Credit Agreement bear interest at specified margins over the London Interbank Offered Rate (LIBOR) of 1.50% to 2.50% for Eurodollar loans or at specified margins over the Alternate Base Rate (ABR) of 0.50% to 1.50% for ABR loans. Such margins will fluctuate based on the utilization of the facility. Borrowings under the Senior Credit Agreement are secured by first priority liens on substantially all of the Company's assets, including pursuant to the terms of the Fifth Amended and Restated Guarantee and Collateral Agreement, all of the assets of, and equity interests in, the Company's subsidiaries. Amounts drawn down on the facility will mature on July 1, 2016.

The Senior Credit Agreement contains customary financial and other covenants, including minimum working capital levels (the ratio of current assets plus the unused commitment under the Senior Credit Agreement to current liabilities) of not less than 1.0 to 1.0 and minimum coverage of interest expenses (as defined in the Senior Credit Agreement) of not less than 2.5 to 1.0. In addition, the Company is subject to covenants limiting dividends and other restricted payments, transactions with affiliates, incurrence of debt, changes of control, asset sales, and liens on properties. At June 30, 2011, the Company was in compliance with its financial debt covenants under the Senior Credit Agreement.

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.

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4. LONG-TERM DEBT (Continued)

In connection with the sale of the 2019 Notes, the Company entered into a Registration Rights Agreement, dated May 20, 2011, among the Company and the Initial Purchasers (the Registration Rights Agreement). Pursuant to the Registration Rights Agreement, the Company agreed to conduct a registered exchange offer for the 2019 Notes or cause to become effective a shelf registration statement providing for the resale of the 2019 Notes. The Company is required to: (i) file an exchange offer registration statement (the Registration Statement) on or prior to 90 days after May 20, 2011, and (ii) use reasonable best efforts to cause such Registration Statement to become effective on or prior to 270 days after May 20, 2011. If the exchange offer is not consummated within 310 days after May 20, 2011, or upon the occurrence of certain other contingencies, the Company has agreed to file a shelf registration statement to cover resales of the 2019 Notes by holders who satisfy certain conditions relating to the provision of information in connection with the shelf registration statement. If the Company fails to comply with certain obligations under the Registration Rights Agreement, it will be required to pay liquidated damages in the form of additional cash interest to the holders of the 2019 Notes.

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, other than a minor subsidiary. 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.

On or prior to June 1, 2015, the Company may redeem all or a part of the 2019 Notes, in whole or in part, at a redemption price equal to 100% of their principal amount plus a make-whole premium, together with accrued and unpaid interest, if any, to the redemption date. The 2019 Notes will be redeemable, in whole or in part, on or after June 1, 2015 at redemption prices equal to the principal amount multiplied by the percentage set forth below, plus accrued and unpaid interest:

Year

2015	103.125	%
2016	101.563	%
2017 and thereafter	100.000	%

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4. LONG-TERM DEBT (Continued)

The Company will be 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 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.

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 9.125% $775 million 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 7.125% $275 million 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 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, other than a minor subsidiary. 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 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

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited) (Continued)

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:

The Company will be 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 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.

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 $7.2 million at June 30, 2011.

On January 27, 2009, the Company completed a private placement offering to eligible purchasers of an aggregate principal amount of $600 million of its 10.5% senior notes due 2014 (the 2014 Notes). The 2014 Notes were issued under and are governed by an indenture dated January 27, 2009, between the Company, U.S. Bank Trust National Association, as trustee, and the Company's subsidiaries named therein as guarantors (the 2014 Indenture).

The 2014 Notes bear interest at a rate of 10.5% per annum, payable semi-annually on February 1 and August 1 of each year. The 2014 Notes will mature on August 1, 2014. The Company will be required to offer to repurchase the 2014 Notes at a purchase price of 101% of the principal amount, plus accrued and unpaid interest, if any, to the redemption date, in the event of a change of control as defined in the 2014 Indenture. The 2014 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, other than a minor subsidiary. 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.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited) (Continued)

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 $33.6 million at June 30, 2011.

On May 13, 2008 and June 19, 2008, the Company issued $500 million principal amount and $300 million principal amount, respectively, of its 7.875% senior notes due 2015 (the 2015 Notes). The 2015 Notes were issued under and are governed by an indenture dated May 13, 2008, between the Company, U.S. Bank Trust National Association, as trustee, and the Company's subsidiaries named therein as guarantors (the 2015 Indenture).

The 2015 Notes bear interest at a rate of 7.875% per annum, payable semi-annually on June 1 and December 1 of each year. The 2015 Notes will mature on June 1, 2015. The Company will be 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 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, other than a minor subsidiary. 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.

On July 12, 2006, the date of the Company's merger with KCS Energy, Inc. (KCS), the Company assumed (pursuant to the Second Supplemental Indenture relating to the 7.125% Senior Notes, also referred to as the 2012 Notes), and subsidiaries of the Company guaranteed (pursuant to the Third Supplemental Indenture relating to such notes), all the obligations (approximately $275 million) of KCS under the 2012 Notes and the Indenture dated April 1, 2004 (the 2012 Indenture) among KCS, U.S. Bank National Association, as trustee, and the subsidiary guarantors named therein, which governs the terms of the 2012 Notes. Interest on the 2012 Notes is payable semi-annually, on each April 1 and October 1. The 2012 Notes are jointly and severally, fully and unconditionally guaranteed on a senior unsecured basis by the Company's subsidiaries, other than a minor subsidiary. Petrohawk Energy Corporation, the issuer of the 2012 Notes, has no material independent assets or operations apart from the assets and operations of its subsidiaries.

In conjunction with the assumption of the 7.125% Senior Notes from KCS, the Company recorded a discount of $13.6 million to be amortized over the remaining life of the notes utilizing the effective interest rate method. The Company had no remaining unamortized discount at June 30, 2011 and $3.5 million at December 31, 2010.

On March 17, 2011, the Company redeemed all of the outstanding 2012 Notes with a portion of the proceeds received from the issuance of the additional 2018 Notes.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited) (Continued)

On April 8, 2004, Mission Resources Corporation (Mission) issued $130 million of its 9.875% senior notes due 2011 (the 2011 Notes). The Company assumed these notes upon the closing of the Company's merger with Mission. In conjunction with the Company's merger with KCS, the Company repurchased substantially all of the 2011 Notes. In connection with the extinguishment of substantially all of the 2011 Notes, the Company requested and received from the noteholders consent to eliminate the debt covenants associated with the 2011 Notes. There were approximately $0.2 million of the notes that were not redeemed and were still outstanding and classified as current as of December 31, 2010. On April 1, 2011, the Company repaid the $0.2 million of the 2011 Notes that were outstanding.

The Company capitalizes certain direct costs associated with the issuance of long-term debt. During the first six months of 2011, the Company capitalized $24.9 million in debt issuance costs associated with the issuances of the additional 2018 Notes and the 2019 Notes, as well as costs incurred for amendments to the Company's Senior Credit Agreement. In the first quarter of 2011, the Company wrote off $0.2 million of debt issuance costs as a result of the additional 2018 Notes issuance and the corresponding reduction of the Company's Senior Credit Agreement. At June 30, 2011 and December 31, 2010, the Company had approximately $64.9 million and $45.9 million, respectively, of debt issuance costs remaining that are being amortized over the lives of the respective debt.

On July 14, 2011, the Company entered into an agreement and plan of merger (Merger Agreement) with BHP Billiton Limited, a corporation organized under the laws of Victoria, Australia (Guarantor), BHP Billiton Petroleum (North America) Inc., a Delaware corporation (Parent) and a wholly owned subsidiary of Guarantor, and North America Holdings II Inc., a Delaware corporation (Merger Sub) and a wholly owned subsidiary of Parent, pursuant to which Merger Sub will commence an offer (Offer) to acquire all of the outstanding shares of the Company's common stock, par value $0.001 per share (Shares), for $38.75 per share, net to the seller in cash, without interest. The Offer commenced on July 25, 2011 and is expected to remain open until August 19, 2011, subject to extension under certain circumstances. If the Offer is consummated, it may result in a change of control under the indentures governing the Company's senior notes discussed above. See Note 15, "Subsequent Events" for further information.

Pursuant to ASC 820, Fair Value Measurements and Disclosures (ASC 820) the Company's determination of fair value incorporates not only the credit standing of the counterparties involved in transactions with the Company resulting in receivables on the Company's unaudited condensed consolidated balance sheets, but also the impact of the Company's nonperformance risk on its own liabilities. ASC 820 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the

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valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. The Company classifies fair value balances based on the observability of those inputs.

The following tables set forth by level within the fair value hierarchy the Company's financial assets and liabilities that were accounted for at fair value as of June 30, 2011 and December 31, 2010. As required by ASC 820, a financial instrument's level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. The Company's assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There were no transfers between fair value hierarchy levels for the six months ended June 30, 2011 and for the year ended December 31, 2010.

Derivatives listed above include collars, swaps, and put options that are carried at fair value. The Company records the net change in the fair value of these positions in "Net gain (loss) on derivative contracts" in the Company's unaudited condensed consolidated statements of operations. The Company is able to value the assets and liabilities based on observable market data for similar instruments, which resulted in the Company reporting its derivatives as Level 2. This observable data includes the forward curve for commodity prices based on quoted markets prices and implied volatility factors related to changes in the forward curves.

As of June 30, 2011 and December 31, 2010, the Company's derivative contracts were with major financial institutions with investment grade credit ratings which are believed to have a minimal credit

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risk. As such, the Company is exposed to credit risk to the extent of nonperformance by the counterparties in the derivative contracts discussed above; however, the Company does not anticipate such nonperformance. Each of the counterparties to the Company's derivative contracts is a lender in the Company's Senior Credit Agreement. The Company did not post collateral under any of these contracts as they are secured under the Senior Credit Agreement.

The following disclosure of the estimated fair value of financial instruments is made in accordance with the requirements of ASC 825, Financial Instruments. The estimated fair value amounts have been determined at discrete points in time based on relevant market information. These estimates involve uncertainties and cannot be determined with precision. The estimated fair value of cash, accounts receivable and accounts payable approximates their carrying value due to their short-term nature. The estimated fair value of the Company's Senior Credit Agreement approximates carrying value because the facility's interest rate approximates current market rates. The following table presents the estimated fair values of the Company's fixed interest rate, long-term debt instruments as of June 30, 2011 and December 31, 2010 (excluding premiums and discounts, deferred premiums on derivative contracts, and any amounts that have been classified as current):

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 June 30, 2011 and December 31, 2010.

For wells drilled, the Company records an asset retirement obligation (ARO) when the total depth of a drilled well is reached and the Company can reasonably estimate the fair value of an obligation to perform site reclamation, dismantle facilities or plug and abandon costs. For gas gathering systems and equipment, the Company records an ARO when the system is placed in service and the Company can reasonably estimate the fair value of an obligation to perform site reclamation and other necessary work. The Company records the ARO liability on the unaudited condensed consolidated balance sheets and capitalizes the cost in "Oil and natural gas properties" or "Gas gathering systems and equipment" during the period in which the obligation is incurred. The Company records the accretion of its ARO liabilities in "Depletion, depreciation and amortization" expense in the unaudited condensed consolidated statements of operations. The additional capitalized costs are depreciated on a unit-of-production basis or straight-line basis.

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The Company recorded the following activity related to its ARO liability for the six months ended June 30, 2011 (in thousands):

The Company leases corporate office space in Houston, Texas and Tulsa, Oklahoma as well as a number of other field office locations. In addition, the Company has lease commitments related to certain vehicles, machinery and equipment under long-term operating leases. Rent expense was $3.7 million and $2.9 million for the six months ended June 30, 2011 and 2010, respectively.

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From time to time, the Company may be a plaintiff or defendant in a pending or threatened legal proceeding arising in the normal course of its business. All known liabilities are accrued based on the Company's best estimate of the potential loss. While the outcome and impact of currently pending legal proceedings cannot be determined, the Company's management and legal counsel believe that the resolution of these proceedings through settlement or adverse judgment will not have a material adverse effect on the Company's condensed consolidated operating results, financial position or cash flows. Please refer to Part II. Other Information, Item 1. Legal Proceedings for further information on pending cases.

The Company is exposed to certain risks relating to its ongoing business operations, such as commodity price risk and interest rate risk. Derivative contracts are utilized to economically hedge its exposure to price fluctuations and reduce the variability in the Company's cash flows associated with anticipated sales of future oil, natural gas and natural gas liquids production. The Company generally hedges a substantial, but varying, portion of anticipated oil, natural gas and natural gas liquids production for the next 12 to 36 months. Derivatives are carried at fair value on the unaudited condensed consolidated balance sheets, with the changes in the fair value included in the unaudited condensed consolidated statements of operations for the period in which the change occurs. Historically, the Company has also entered into interest rate swaps to mitigate exposure to market rate fluctuations by converting variable interest rates (such as those on the Company's Senior Credit Agreement) to fixed interest rates and may do so at some point in the future as situations present themselves.

It is the Company's policy to enter into derivative contracts, including interest rate swaps, only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers. Each of the counterparties to the Company's derivative contracts is a lender in the Company's Senior Credit Agreement. The Company did not post collateral under any of these contracts as they are secured under the Company's Senior Credit Agreement.

At June 30, 2011 the Company had entered into commodity collars and swaps. The Company has elected to not designate any of its derivative contracts for hedge accounting. Accordingly, the Company records the net change in the mark-to-market valuation of these derivative contracts, as well as all payments and receipts on settled derivative contracts, in "Net gain (loss) on derivatives contracts" on the unaudited condensed consolidated statements of operations.

At June 30, 2011, the Company had 109 open commodity derivative contracts summarized in the tables below: 11 natural gas swap arrangements, 76 natural gas collar arrangements, 21 crude oil collar

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arrangements, and one natural gas liquids swap (which was an ethane swap). Derivative commodity contracts settle based on NYMEX WTI and Henry Hub prices, or the applicable information service for the Company's natural gas liquids contracts, which may have differed from the actual price received by the Company for the sale of its oil, natural gas and natural gas liquids production.

At December 31, 2010, the Company had 79 open commodity derivative contracts summarized in the tables below: 60 natural gas collar arrangements, two natural gas swap arrangements, 16 crude oil collar arrangements, and one natural gas liquids swap (which was an ethane swap). Derivative commodity contracts in 2010 settled based on NYMEX WTI and Henry Hub prices, or the applicable information service for the Company's natural gas liquids contracts, which may have differed from the actual price received by the Company for the sale of its oil, natural gas and natural gas liquids production.

All derivative contracts are recorded at fair market value in accordance with ASC 815 and ASC 820 and included in the unaudited condensed consolidated balance sheets as assets or liabilities. The following table summarizes the location and fair value amounts of all derivative contracts in the unaudited condensed consolidated balance sheets as of June 30, 2011 and December 31, 2010:

The following table summarizes the location and amounts of the Company's realized and unrealized gains and losses on derivative contracts in the Company's unaudited condensed consolidated statements of operations:

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During the six months ended June 30, 2011, the Company granted stock options covering 2.3 million shares of common stock to employees of the Company. The stock options have exercise prices ranging from $20.57 to $26.14 with a weighted average price of $20.61. These awards vest over a three year period at a rate of one-third on the annual anniversary date of the grant, subject to acceleration in the event of a change of control of the Company, and expire ten years from the grant date. At June 30, 2011, the unrecognized compensation expense related to non-vested stock appreciation rights and stock options totaled $26.8 million and will be recognized on a straight line basis over the weighted average remaining vesting period of 1.4 years.

During the six months ended June 30, 2010, the Company granted stock options covering 2.1 million shares of common stock to employees of the Company. The stock options have exercise prices ranging from $17.90 to $23.58 with a weighted average price of $21.20. These awards vest over a three year period at a rate of one-third on the annual anniversary date of the grant, subject to acceleration in the event of a change of control of the Company, and expire ten years from the grant date. At June 30, 2010, the unrecognized compensation expense related to non-vested stock appreciation rights and stock options totaled $20.3 million and will be recognized on a straight line basis over the weighted average remaining vesting period of 1.4 years.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited) (Continued)

During the six months ended June 30, 2011, the Company granted 1.3 million shares of restricted stock to employees of the Company and non-employee directors. These restricted shares were granted at prices ranging from $20.57 to $26.14 with a weighted average price of $20.82. Employee shares vest over a three-year period at a rate of one-third on the annual anniversary date of the grant, subject to acceleration in the event of a change of control of the Company, and the non-employee directors' shares vest six-months from the date of grant. At June 30, 2011, the unrecognized compensation expense related to non-vested restricted stock totaled $29.4 million and was to be recognized on a straight line basis over the weighted average remaining vesting period of 1.4 years.

During the six months ended June 30, 2010, the Company granted 1.1 million shares of restricted stock to employees of the Company and non-employee directors. These restricted shares were granted at prices ranging from $17.90 to $23.58 with a weighted average price of $21.21. Employee shares vest over a three-year period at a rate of one-third on the annual anniversary date of the grant, subject to acceleration in the event of a change of control of the Company, and the non-employee directors' shares vest six-months from the date of grant. At June 30, 2010, the unrecognized compensation expense related to non-vested restricted stock totaled $23.5 million and was to be recognized on a straight line basis over the weighted average remaining vesting period of 1.4 years.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited) (Continued)

The assumptions used in calculating the fair value of the Company's stock-based compensation are disclosed in the following table:

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited) (Continued)

Common stock equivalents, including stock options and stock appreciation rights (SARS), totaling 0.1 million shares were not included in the computations of diluted earnings per share of common stock for the three and six months ended June 30, 2011, because the grant prices were greater than the average market price of the common shares. Common stock equivalents, including stock options and SARS, totaling 0.2 million and 2.2 million shares were not included in the computations of diluted earnings per share because the effect would have been anti-dilutive for the three and six months ended June 30, 2010, respectively, because the grant prices were greater than the average market price of the common shares.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited) (Continued)

In accordance with ASC 280, Segment Reporting (ASC 280), the Company has identified two reportable segments: oil and natural gas production and midstream operations. The oil and natural gas production segment is responsible for acquisition, exploration, development and production of oil and natural gas properties, while the midstream operations segment is responsible for gathering and treating natural gas for the Company and third parties. The Company's Chief Operating Decision Maker evaluates the performance of the reportable segments based on "Income from continuing operations before income taxes."

As discussed in Note 2, "Acquisitions and Divestitures" and Note 13 "Equity Method Investment," on May 21, 2010, the Company contributed its Haynesville Shale gathering and treating business to form a joint venture entity with Kinder Morgan. The Company accounts for its 50% investment in the joint venture entity, KinderHawk, under the equity method and the revenues and expenses associated with the Haynesville Shale gathering and treating business are no longer presented within the Company's consolidated revenues and expenses in the unaudited condensed consolidated statements of operations. The Company pays to KinderHawk negotiated gathering and treating fees, which are included in "Gathering, transportation and other" on the unaudited condensed consolidated statements of operations, and are discussed further in Note 2, "Acquisitions and Divestitures." On July 1, 2011, the Company sold its remaining 50% membership interest in KinderHawk. See Note 15, "Subsequent Events," for additional details of this transaction.

On January 7, 2011, the Company sold its midstream operations in the Fayetteville Shale. The revenues and expenses associated with the Fayetteville Shale midstream operations have been classified as discontinued operations in the condensed unaudited consolidated statements of operations for all periods presented, in the line item "Loss from discontinued operations, net of income taxes." See Note 14, "Discontinued Operations," for further discussion of the presentation of the Company's Fayetteville Shale midstream assets as discontinued operations. The segment information presented in the tables below is amounts related to continuing operations.

The Company's oil and natural gas segment and midstream segment revenues and expenses include intersegment transactions, which are generally based on transactions made at market-related rates. Consolidated revenues and expenses reflect the elimination of all intercompany transactions. The accounting policies of the reporting segments are the same as those described in the "Summary of Significant Events and Accounting Policies" in Note 1 of the 2010 Annual Report on Form 10-K.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited) (Continued)

Summarized financial information concerning our reportable segments is shown in the following table (in thousands):

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited) (Continued)

The Company's investment in an unconsolidated entity in which the Company does not have a majority interest, but does have significant influence, is accounted for under the equity method. Under the equity method of accounting, the Company's share of net income (loss) from its equity affiliate is reflected as an increase (decrease) in its investment account in "Other noncurrent assets" and is also recorded as "Equity investment income" in "Other income (expenses)." Distributions from the equity affiliate are recorded as reductions of the Company's investment and contributions to the equity affiliate are recorded as increases of the Company's investment.

The Company reviews its equity method investment for potential impairment whenever events or changes in circumstances indicate that an other-than-temporary decline in the value of the investment has occurred.

As discussed in Note 2, "Acquisitions and Divestitures," on May 21, 2010, the Company and Kinder Morgan formed a joint venture entity, KinderHawk, which engages in the natural gas midstream business in Northwest Louisiana, focused on the Haynesville and Lower Bossier Shales. As part of the transaction, the Company contributed its Haynesville Shale gathering and treating business in Northwest Louisiana to KinderHawk and Kinder Morgan contributed approximately $917 million in cash, to the new entity. The cash was distributed by KinderHawk to the Company and each of the Company and Kinder Morgan owns a 50% membership interest in KinderHawk. The Company accounts for its 50% membership interest in KinderHawk as an equity method investment. As of June 30, 2011, the Company's investment in KinderHawk totaled $212 million. The Company contributed assets to KinderHawk and recorded its investment at the historic book value of the assets while KinderHawk recorded the contributed assets at their fair market value. The difference between the carrying amount of the Company's investment in KinderHawk and the Company's underlying equity in KinderHawk's assets creates a basis differential which is amortized over the useful life of gas gathering assets. For the six months ended June 30, 2011, the Company recognized $4.8 million of the basis differential in "Equity investment income" on the unaudited condensed consolidated statements of operations.

At May 21, 2010, as of a result of the transaction, the Company recorded a deferred gain of approximately $719.4 million for the difference between 50% of the net carrying value of the assets the Company contributed to the joint venture and the net cash proceeds from KinderHawk, representing the cash contributed by Kinder Morgan at closing for its 50% membership interest in KinderHawk. The Company recognizes the portion of the deferred gain equal to its capital commitment as contributions to KinderHawk are made or upon expiration of the capital commitment at December 31, 2011. On July 1, 2011, the Company sold its remaining 50% membership interest in KinderHawk. See Note 15, "Subsequent Events," for additional details of the transaction. In conjunction with the closing of the Company's sale of its remaining 50% membership interest in KinderHawk, the balance of the Company's capital commitment to KinderHawk was relieved. In addition to the capital commitment, the Company guaranteed to deliver certain minimum annual volumes of natural gas through the Haynesville gathering system through May 2015, as discussed in Note 2, "Acquisitions and Divestitures." The Company recognizes the remaining deferred gain as volumes are delivered through the Haynesville gathering system through May 2015. The Company's obligation to deliver minimum annual volumes of natural gas remains in effect following the sale of the Company's remaining 50% membership interest in KinderHawk on July 1, 2011, and the Company will continue to recognize the deferred gain

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associated with the delivered volumes through May 2015. As of June 30, 2011, the balance of the Company's deferred gain was $469.1 million.

On December 22, 2010, the Company completed the sale of its interest in natural gas properties and other operating property and equipment in the Fayetteville Shale. On January 7, 2011, the Company completed the sale of its midstream assets in the Fayetteville Shale. For all periods presented, the Company classified the operations associated with the Fayetteville Shale gas gathering systems and equipment, which are part of the Company's midstream operations segment, and the Fayetteville Shale other operating property and equipment, which are part of the Company's oil and natural gas production segment, as "Loss from discontinued operations, net of income taxes" in the unaudited condensed consolidated statements of operations.

On March 1, 2011, the Company completed the sale of its interest in the Buffalo Hump Ranch located in Van Buren County, Arkansas for approximately $2.1 million in cash. A loss on the sale of approximately $4.3 million before income taxes, $2.7 million after taxes was recorded during the first quarter of 2011 in "Loss from discontinued operations, net of income taxes" in the unaudited condensed consolidated statements of operations. The transaction had an effective date of March 1, 2011.

As of December 31, 2010, the Fayetteville Shale midstream assets were classified as "Assets held for sale" on the Company's unaudited condensed consolidated balance sheet. "Assets held for sale" were recorded at the lesser of the carrying amount or the fair value less costs to sell, which resulted in a write down of the carrying amount of approximately $69.7 million in the year ended December 31, 2010. In conjunction with the sale of the other operating property and equipment, the Company recorded a loss of approximately $0.5 million in the year ended December 31, 2010.

The following table contains summarized income statement information for the Fayetteville Shale midstream operations and other operating property and equipment for the periods indicated (in thousands):

On July 14, 2011, the Company entered into an agreement and plan of merger (Merger Agreement) with BHP Billiton Limited, a corporation organized under the laws of Victoria, Australia

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(Guarantor), BHP Billiton Petroleum (North America) Inc., a Delaware corporation (Parent) and a wholly owned subsidiary of Guarantor, and North America Holdings II Inc., a Delaware corporation (Merger Sub) and a wholly owned subsidiary of Parent, pursuant to which Merger Sub will commence an offer (Offer) to acquire all of the outstanding shares of the Company's common stock, par value $0.001 per share (Shares), for $38.75 per share, net to the seller in cash, without interest. The Offer commenced on July 25, 2011 and is expected to remain open until August 19, 2011, subject to extension under certain circumstances. The Merger Agreement also provides that following consummation of the Offer and satisfaction or waiver of certain customary conditions, Merger Sub will be merged with and into the Company, with the Company surviving as a wholly owned subsidiary of Parent.

Consummation of the Offer is subject to several conditions, including: (i) that a majority of the Shares outstanding (generally determined on a fully diluted basis) be validly tendered and not properly withdrawn prior to the expiration date of the Offer (as such expiration date may be extended pursuant to the Merger Agreement); (ii) the expiration or early termination of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended (which early termination was granted on July 22, 2011); (iii) clearance from the Committee on Foreign Investment in the United States; (iv) the absence of a material adverse effect on the Company; and (v) certain other customary conditions.

The Merger Agreement contains certain termination rights of Parent and the Company and provides that, upon the termination of the Merger Agreement under specified circumstances, the Company will be required to pay Parent a termination fee of $395 million.

At Parent's request and direction, and as an inducement to Parent's willingness to enter into the Merger Agreement, the Company entered into retention agreements (Retention Agreements) with certain of the Company's executive officers contemporaneously with the execution of the Merger Agreement. The Retention Agreements are to be effective only if and when Parent accepts for payment Shares validly tendered and not withdrawn pursuant to the terms and conditions of the Offer (Acceptance Time). The Retention Agreements continue the employment of each executive with the Company for a period of time following the Acceptance Time. For those executives who currently have employment agreements with the Company, such employment agreements are superseded and replaced in their entirety by the Retention Agreements as of the effective time of such Retention Agreement. Mr. Wilson also entered into a consulting agreement (Consulting Agreement) with the Company beginning after the retention date specified in Mr. Wilson's Retention Agreement and ending six months thereafter under which Mr. Wilson will provide services to the Company and pursuant to which he will be entitled to separately specified compensation.

The Retention Agreements provide for minimum base salary, bonus and retention bonus payments to which each executive party thereto is entitled for varying periods of time and, for certain executives, also provide for grants of Guarantor restricted stock units. Each Retention Agreement also provides for a gross-up payment (equal to the amount of any excise tax) in the event that any payment or benefit becomes subject to an excise tax imposed by Section 4999 of the Internal Revenue Code of 1986, as amended.

Under the terms of the Retention Agreements, each executive is also entitled to severance benefits in the event of a termination of an executive's employment under certain circumstances.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited) (Continued)

Additional information regarding the Merger Agreement, Retention Agreements and Consulting Agreement is set forth in the Company's Form 8-K filed on July 20, 2011.

On July 1, 2011, Petrohawk, Hawk Field Services, and EagleHawk Field Services LLC (EagleHawk), a wholly owned subsidiary of Petrohawk (Petrohawk, Hawk Field Services and EagleHawk being collectively referred to herein as, the Company), closed previously announced transactions with KM Gathering and KM Eagle Gathering LLC (Eagle Gathering), each of which is an affiliate of Kinder Morgan, in which Hawk Field Services sold (i) its remaining 50% membership interest in KinderHawk to KM Gathering and (ii) a 25% interest in EagleHawk to Eagle Gathering, in exchange for aggregate cash consideration after closing adjustments, of approximately $836 million, subject to post-closing purchase price adjustments. In conjunction with the closing of the transactions, the balance of the Company's capital commitment to KinderHawk was relieved. This remaining capital commitment was approximately $41.4 million as of June 30, 2011. The Company's commitment to deliver certain minimum annual volumes of natural gas through the Haynesville gathering system through May 2015 was not relieved in the sale of the remaining 50% membership interest in KinderHawk. The effective date of the transactions is July 1, 2011.

EagleHawk is a newly formed entity that engages in the natural gas midstream business in the Eagle Ford Shale in South Texas. EagleHawk holds the Company's gathering and treating assets and business serving the Company's Hawkville and Black Hawk fields in the Eagle Ford Shale. EagleHawk has agreements with the Company covering gathering and treating of natural gas and transportation of condensate and pursuant to which the Company dedicates its production from its Eagle Ford Shale leases. Hawk Field Services manages EagleHawk's operations.

Effective July 1, 2011, the Company amended its existing credit facility, the Senior Credit Agreement, dated August 2, 2010 by entering into the Fourth Amendment to the Fifth Amended and Restated Senior Revolving Credit Agreement (the Fourth Amendment). The Fourth Amendment was entered into to facilitate the closing of the EagleHawk joint venture. The Fourth Amendment, among other things, permitted Hawk Field Services to: convey its Eagle Ford Shale gathering and treating business in South Texas to EagleHawk; sell a 25% equity interest in EagleHawk to Kinder Morgan; enter into and abide by the terms of the operative documents governing the formation and operation of EagleHawk, and reaffirmed the oil and gas component of the Company's borrowing base under the Senior Credit Agreement at $1.8 billion, while reducing to zero the midstream component of the Company's borrowing base.

Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations

The following discussion is intended to assist in understanding our results of operations and our current financial position for the three and six months ended June 30, 2011 and 2010 and should be read in conjunction with our unaudited condensed consolidated financial statements and the notes thereto included in this Quarterly Report on Form 10-Q and with the consolidated financial statements, notes and management's discussion and analysis included in our Annual Report on Form 10-K for the year ended December 31, 2010.

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.

We are an independent oil and natural gas company engaged in the exploration, development and production of predominately natural gas properties located in the United States. Our business is comprised of an oil and natural gas production segment and a midstream operations segment. We organize our oil and natural gas production operations into two principal regions: the Mid-Continent, which includes our Louisiana, East Texas and West Texas properties; and the Western, which includes our South Texas properties. Our midstream operations segment consists of our gathering subsidiary, Hawk Field Services, LLC (Hawk Field Services) which was formed to integrate our active drilling program with activities of third parties and to develop additional gathering and treating capacity. Hawk Field Services currently serves the Eagle Ford Shale in South Texas through our investment in Eagle Hawk Field Services LLC.

Historically, we have grown through acquisitions of proved oil and natural gas reserves and undeveloped acreage, with a focus on properties within our core operating areas that we believe have significant development and exploration opportunities. In the past few years, we significantly expanded our leasehold position in resource plays, particularly in the Haynesville Shale play in Northern Louisiana and East Texas and the Eagle Ford Shale play in South Texas, and we have acquired a position in the Permian Basin in West Texas. We focus our operations in regions where we believe we can apply our technical experience and economies of scale to increase production and proved reserves while lowering unit lease operating costs. The vast majority of our acreage in these plays is currently undeveloped. Typically, the leases we own require that production in paying quantities be established on units under the lease within the primary lease term (generally three to five years) or the lease will expire.

Our average daily oil and natural gas production increased 42% in the first six months of 2011 compared to the same period in the prior year. During the first six months of 2011, we averaged 885 million cubic feet of natural gas equivalent (Mmcfe) per day (Mmcfe/d) compared to average daily production of 625 Mmcfe/d during the first six months of 2010. The increase in production compared to the prior year period is driven by our drilling successes in the Haynesville and Eagle Ford Shales as our production gains have more than made up for production sold during 2010. During the first six months of 2011, we drilled or participated in the drilling of 248 gross wells (106.4 net wells), all of which were successful.

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 and our related commodity price hedging activities, 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.

During the first quarter of 2011, we announced our intention to sell approximately $1.0 billion in non-core assets to fund a portion of our acquisition and capital expenditure budget for 2011.

On July 1, 2011, we along with our subsidiaries Hawk Field Services and EagleHawk Field Services LLC (EagleHawk), closed previously announced transactions with KM Gathering LLC (KM Gathering) and KM Eagle Gathering LLC (Eagle Gathering), each of which is an affiliate of Kinder Morgan Energy Partners, L.P. (Kinder Morgan), a publicly traded master limited partnership, in which Hawk Field Services sold (i) its remaining 50% membership interest in KinderHawk to KM Gathering and (ii) a 25% interest in EagleHawk to Eagle Gathering, in exchange for aggregate cash consideration after closing adjustments, of approximately $836 million, subject to post-closing purchase price adjustments. In conjunction with the closing of these transactions, our remaining capital commitment to KinderHawk was relieved. This remaining capital commitment was approximately $41.4 million as of June 30, 2011. Our commitment to deliver certain minimum annual volumes of natural gas through the Haynesville gathering system through May 2015 was not relieved in the sale of the remaining 50% membership interest in KinderHawk. EagleHawk is a newly formed entity managed by Hawk Field Services that engages in the natural gas midstream business in the Eagle Ford Shale in South Texas. At the closing of the transactions, EagleHawk holds our gathering and treating assets and business serving our Hawkville and Black Hawk fields in the Eagle Ford Shale. EagleHawk has agreements with us covering gathering and treating and pursuant to which we dedicate our production from our Eagle Ford Shale leases.

On March 11, 2011 an independent third party exercised their option to acquire a portion of our interest in oil and natural gas properties in the Black Hawk Field of the Eagle Ford Shale. Proceeds from this transaction were approximately $74 million and were recorded as a reduction to the carrying value of our full cost pool with no gain or loss recorded. The effective date of the transaction was March 1, 2011. On January 7, 2011, we completed the sale of our midstream assets in the Fayetteville Shale for approximately $75 million in cash, before customary closing adjustments. The transaction had an effective date of October 1, 2010.

On May 20, 2011, we issued $600 million aggregate principal amount of our 6.25% senior notes due 2019 (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 from the 2019 Notes were utilized to repay borrowings outstanding under our senior revolving credit facility and for working capital for general corporate purposes.

On January 31, 2011, we completed the issuance of an additional $400 million aggregate principal amount of our 7.25% senior notes due 2018 (the additional 2018 Notes). 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 our 7.125% $275 million senior notes due 2012 (the 2012 Notes).

During late 2010 and early 2011, we began acquiring acreage in the Permian Basin of West Texas. We have acquired or committed to acquire approximately 325,000 net acres in the Midland and Delaware Basins and we expect to operate over 90% of the acreage. We expect to spend approximately $75 million on drilling and completions in the new Basins during 2011 and we expect to gradually increase capital spending in the area in the future, subject to drilling results.

Our 2011 capital budget is focused on the development of non-proved reserve locations in our Haynesville, Lower Bossier, and Eagle Ford Shale plays so that we can hold our acreage in these areas. Capital spending for 2011 was initially estimated at $2.3 billion, of which $1.9 billion was allocated for drilling and completions, $200 million was allocated for midstream operations and $200 million was

allocated for potential acquisitions. Our estimated capital expenditures for drilling and completions was increased to $2.0 billion, our budget for potential acquisitions was increased to $600 million due to our addition of acreage in the Permian Basin as discussed above, and our budget for midstream operations was increased to $250 million to accomodate accelerated operations in the Eagle Ford Shale. Of the $2.0 billion budget for drilling and completions, $950 million is planned for the Haynesville and Lower Bossier Shales, which we expect will fulfill our lease-holding goals, $950 million is budgeted for the Eagle Ford Shale, $75 million is planned for the Permian Basin and $25 million is planned for various other projects. Our 2011 drilling and completion budget contemplates an increase in drilling activity in the Eagle Ford Shale throughout the year, a significant decrease in the Haynesville Shale operated rig count in the second half of the year as our lease-holding activities are substantially completed, and the beginning of the development of our new Permian Basin acreage. Our 2011 program will emphasize the development of our extensive condensate-rich properties, largely in the Eagle Ford Shale, and a shift away from dry gas development in our core areas. Our drilling and completion budget for 2011 is based on our current view of market conditions, our objective of accelerating development of certain areas of our Eagle Ford Shale position, and our desire to reduce capital allocated to pure natural gas drilling once our Haynesville Shale lease-holding activities are effectively completed.

We expect to fund our 2011 capital budget with cash flows from operations, proceeds from asset dispositions, a portion of the proceeds from our 2011 senior note offerings and borrowings under our Senior Credit Agreement. We strive to maintain financial flexibility and may access capital markets as necessary to maintain substantial borrowing capacity under our Senior Credit Agreement, facilitate drilling on our large undeveloped acreage position and selectively expand our acreage position and infrastructure projects. In the event our cash flows or proceeds from potential asset dispositions are materially less than anticipated and other sources of capital we historically have utilized are not available on acceptable terms, we may curtail our capital spending.

On July 14, 2011, we entered into an agreement and plan of merger with BHP Billiton Limited, a corporation organized under the laws of Victoria, Australia (Guarantor), BHP Billiton Petroleum (North America) Inc., a Delaware corporation (Parent) and a wholly owned subsidiary of Guarantor, and North America Holdings II Inc., a Delaware corporation (Merger Sub) and a wholly owned subsidiary of Parent, pursuant to which Merger Sub will commence an offer (Offer) to acquire all of the outstanding shares of our common stock, par value $0.001 per share, for $38.75 per share, net to the seller in cash, without interest. The Offer commenced on July 25, 2011 and will remain open until August 19, 2011, subject to extension under certain circumstances. The Merger Agreement also provides that following consummation of the Offer and satisfaction or waiver of certain customary conditions, Merger Sub will be merged with and into us, and we will survive as a wholly owned subsidiary of Parent.

The Merger Agreement contains certain termination rights of Parent and us and provides that, upon the termination of the Merger Agreement under specified circumstances, we will be required to pay Parent a termination fee of $395 million. Additional information regarding the Merger Agreement can be found in our Form 8-K filed on July 20, 2011.

Our primary sources of capital and liquidity are internally generated cash flows from operations, proceeds from asset dispositions, availability under our Senior Credit Agreement, and access to capital markets, to the extent available. Volatility in the capital markets could adversely impact our access to capital, which could reduce our ability to execute our development and acquisition plans, our ability to replace our reserves and our production levels. We continuously monitor our liquidity and the capital markets and evaluate our development plans in light of a variety of factors, including, but not limited to, our cash flows, capital resources and drilling success.

Our future capital resources and liquidity depend, in part, on our success in developing our leasehold interests. Cash is required to fund capital expenditures necessary to offset inherent declines in our production and proven reserves, which is typical in the capital-intensive oil and natural gas industry. Future success in growing reserves and production will be highly dependent on our capital resources and our success in finding additional reserves. On May 20, 2011, we issued $600 million aggregate principal amount of our 6.25% senior notes due 2019. The net proceeds from the sale of the 2019 Notes were approximately $589 million (after deducting offering fees and expenses). The proceeds from the 2019 Notes were utilized to repay borrowings outstanding under our senior revolving credit facility and for working capital for general corporate purposes. On January 31, 2011, we completed the issuance of $400 million aggregate principal amount of the additional 2018 Notes. A portion of the proceeds of the additional 2018 Notes were utilized to redeem our 7.125% $275 million senior notes due 2012.

On April 29, 2011, we amended our Senior Credit Agreement, the Fifth Amended and Restated Senior Revolving Credit Agreement, as amended on November 8, 2010 and December 22, 2010, by entering into the Third Amendment to the Fifth Amended and Restated Senior Revolving Credit Agreement (the Third Amendment), among us, each of the lenders from time to time party thereto (the Lenders), BNP Paribas, as administrative agent for the Lenders, Bank of America, N.A. and Bank of Montreal as co-syndication agents for the Lenders, and JPMorgan Chase Bank, N.A. and Wells Fargo Bank, N.A., as co-documentation agents for the Lenders. Among other things, the Third Amendment: (a) increased our borrowing base to $1.9 billion, $1.8 billion of which related to our oil and natural gas properties and $100 million of which related to our midstream assets (limited as described below); (b) reduced interest rates such that amounts outstanding under the Senior Credit Agreement will bear interest at specified margins over the London Interbank Offered Rate (LIBOR) of 1.50% to 2.50% for Eurodollar loans or at specified margins over the Alternate Base Rate (ABR) of 0.50% to 1.50% for ABR loans, which margins will fluctuate based on the utilization of the facility; (c) extended the maturity date of the facility from July 1, 2014 to July 1, 2016; and (d) increased the amount of the facility from $2.0 billion to $2.5 billion. The portion of the Senior Credit Agreement's borrowing base which relates to our oil and natural gas properties is redetermined on a semi-annual basis (with us and the lenders each having the right to one annual interim unscheduled redetermination) and adjusted based on our oil and natural gas properties, reserves, other indebtedness and other relevant factors. The component of the borrowing base related to our midstream assets is limited to the lesser of $100 million or 3.5 times midstream EBITDA and is calculated quarterly. As of June 30, 2011, the full capacity of the midstream component of the borrowing base was available. Our ability to utilize the full amount of our borrowing capacity is influenced by a variety of factors, including redeterminations of our borrowing base, and covenants under our Senior Credit Agreement and our senior unsecured debt indentures. Additionally, our borrowing base is subject to a reduction equal to the product of $0.25 multiplied by the stated principal amount (without regard to any initial issue discount) of any unsecured senior or senior subordinated notes that we may issue. In connection with the issuance of our 6.25% $600 million senior notes due 2019, as described above, our lenders waived the automatic reduction of our borrowing base. As a result, our borrowing base under the Senior Credit Agreement remained at $1.9 billion upon the issuance of the 2019 Notes.

Effective July 1, 2011, we amended our Senior Credit Agreement by entering into the Fourth Amendment to the Fifth Amended and Restated Senior Revolving Credit Agreement (the Fourth Amendment). The Fourth Amendment was entered into to facilitate the closing of the EagleHawk joint venture. The Fourth Amendment, among other things, allows Hawk Field Services to: convey its Eagle Ford Shale gathering and treating business in South Texas to EagleHawk; sell a 25% equity interest in EagleHawk to Kinder Morgan; enter into and abide by the terms of the operative documents governing the formation and operation of EagleHawk, and reaffirms the oil and gas component of our borrowing base under the Senior Credit Agreement at $1.8 billion, while reducing to zero the midstream component of our borrowing base.

Our Senior Credit Agreement contains customary financial and other covenants, including minimum working capital levels (the ratio of current assets plus the unused commitment under the Senior Credit Agreement to current liabilities) of not less than 1.0 to 1.0 and minimum coverage of interest expenses (as defined in the Senior Credit Agreement) of not less than 2.5 to 1.0. We are subject to additional covenants limiting dividends and other restricted payments, transactions with affiliates, incurrence of debt, changes of control, asset sales, and liens on properties. Additionally, the indentures governing our senior unsecured debt contain covenants limiting our ability to incur additional indebtedness, including borrowings under our Senior Credit Agreement, unless we meet one of two alternative tests. The first test applies to all indebtedness and requires that after giving effect to the incurrence of additional debt the ratio of our adjusted consolidated EBITDA (as defined in our indentures) to our adjusted consolidated interest expense over the trailing four fiscal quarters will be, under the most restrictive indentures, at least 2.5 to 1.0. The second test applies only to borrowings under our Senior Credit Agreement that do not meet the first test and limits these borrowings to the greater of a fixed sum of, under the most restrictive indentures, $1 billion and 30% of our adjusted consolidated net tangible assets (as defined in all of our indentures), which is largely calculated based upon the discounted future net revenues from our proved oil and natural gas reserves as of the end of each year. As of June 30, 2011, we had $559.0 million of debt outstanding under the Senior Credit Agreement and $1.3 billion of additional borrowing capacity available. At June 30, 2011, we were in compliance with the financial covenants under our Senior Credit Agreement.

Our borrowing base, EBITDA and consolidated net tangible assets are significantly influenced by, among other things, oil and natural gas prices. We strive to maintain financial flexibility while continuing our aggressive drilling plans and may access the capital markets to, among other things, maintain substantial borrowing capacity under our Senior Credit Agreement, facilitate drilling on our large undeveloped acreage position and permit us to selectively expand our acreage position and infrastructure projects. Our ability to complete future debt and equity offerings is subject to market conditions.

In conjunction with the KinderHawk joint venture (a joint venture in which our wholly owned subsidiary, Hawk Field Services, and Kinder Morgan each own a 50% membership interest), we are committed to fund up to an additional $41.4 million, as of June 30, 2011, in capital contributions to KinderHawk during 2011, if required by KinderHawk to fund its capital expenditures. On July 1, 2011, in conjunction with the closing of the sale of our remaining 50% membership interest in KinderHawk, the balance of our capital commitment to KinderHawk was relieved. See Item 1. Condensed Consolidated Financial Statements (Unaudited)—Note 15, "Subsequent Events" for more details.

Our long-term cash flows are subject to a number of variables including our level of oil and natural gas production and commodity prices, as well as various economic conditions that have historically affected the oil and natural gas industry. If natural gas prices remain at their current levels for a prolonged period of time or if oil and natural gas prices decline, our ability to fund our capital expenditures, reduce debt, meet our financial obligations and become profitable may be materially impacted.

Our primary sources of cash for the six months ended June 30, 2011 were from operating and financing activities in addition to funds from asset sales. Our primary sources of cash for the six months ended June 30, 2010 were funds from asset sales and operating activities, which were partially offset by net repayments of our Senior Credit Agreement and cash used in investing activities to fund our drilling program and acquisition activities. Operating cash flow fluctuations were substantially driven by changes in commodity prices and changes in our production volumes. Working capital was substantially influenced by these variables. Fluctuation in cash flow may result in an increase or decrease in our future capital expenditures. Prices for oil and natural gas have historically been subject to seasonal influences typically characterized by peak demand and higher prices in the winter heating season; however, the impact of other risks and uncertainties have influenced prices throughout recent years. See "Results of Operations" below for a review of the impact of prices and volumes on revenues.

Operating Activities. Net cash provided by operating activities for the six months ended June 30, 2011 and 2010 were $540.0 million and $319.5 million, respectively.

Net cash provided by operating activities increased in 2011 primarily due our drilling successes in the Haynesville and Eagle Ford Shales, as well as a 4% increase in our average realized natural gas equivalent price. Production for the first six months of 2011 averaged 885 Mmcfe/d compared to 625 Mmcfe/d during the same period of 2010, a 42% increase. Our realized natural gas equivalent price increased $0.17 per Mcfe to $4.94 from $4.77 in the prior year. As a result of our 2011 capital budget program, we expect to continue to increase our production volumes throughout 2011. However, we are unable to predict future production levels or future commodity prices with certainty, and, therefore, we cannot provide any assurance about future levels of net cash provided by operating activities.

Investing Activities. The primary driver of cash used in investing activities is capital spending, inclusive of acquisitions and net of dispositions. Cash used in investing activities was $1.7 billion and $92.1 million for the six months ended June 30, 2011 and 2010, respectively.

During the first six months of 2011, we spent $1.7 billion on oil and natural gas capital expenditures. In the first six months of 2011, we participated in the drilling of 248 gross wells (106.4 net wells). We spent an additional $134.7 million on other operating property and equipment capital expenditures, primarily to fund the development of our gathering systems in the Eagle Ford Shale in South Texas.

During the first six months of 2011, we purchased and redeemed $330.0 million of marketable securities. These marketable securities were classified and accounted for as trading securities and were used primarily to fund a portion of our 2011 capital program.

recorded as a reduction to the carrying value of our full cost pool with no gain or loss recorded. The effective date of the transaction was March 1, 2011.

On December 22, 2010, we completed the sale of our interest in natural gas properties and other operating property and equipment in the Fayetteville Shale for $575 million in cash, before customary closing adjustments. Proceeds from the sale of the interest in natural gas properties were recorded as a reduction to the carrying value of our full cost pool with no gain or loss recorded. In conjunction with the sale of the other operating property and equipment, we recorded a loss of approximately $0.5 million in the year ended December 31, 2010. On January 7, 2011, we completed the sale of our midstream assets in the Fayetteville Shale for approximately $75 million in cash, before customary closing adjustments. Both transactions had an effective date of October 1, 2010. During the first six months of 2011, we have made no cash contributions to KinderHawk and have received distributions of $36.2 million, which are recorded in cash flows from operating activities.

During the first six months of 2010, we spent $1.2 billion on oil and natural gas capital expenditures and participated in the drilling of 403 gross wells (103.8 net wells). We spent an additional $173.8 million on other operating property and equipment expenditures, primarily to fund the development of our gathering systems in the Haynesville Shale in Northwest Louisiana and the Eagle Ford Shale in South Texas.

During the first six months of 2010, we purchased a net $281.0 million of marketable securities. These marketable securities were classified and accounted for as trading securities and were used primarily to fund a portion of our 2010 capital program.

During the first six months of 2010, we had a net decrease in restricted cash of $156.5 million. Restricted cash was used to fund a portion of our 2010 oil and natural gas acquisitions.

On May 21, 2010, our wholly owned subsidiary, Hawk Field Services, and Kinder Morgan entered into a joint venture arrangement to create a new entity, KinderHawk, which engages in the natural gas midstream business in Northwest Louisiana, focused on the Haynesville Shale formation. Hawk Field Services contributed to KinderHawk our Haynesville Shale gathering and treating business in Northwest Louisiana, and Kinder Morgan contributed approximately $917 million in cash ($875 million for a 50% membership interest in KinderHawk and $42 million for certain closing adjustments including 2010 capital expenditures through the closing date) to KinderHawk. We, along with Kinder Morgan, own a 50% membership interest in KinderHawk. KinderHawk distributed the approximate $917 million to us.

On May 12, 2010, we completed the sale of our interest in Terryville Field, located in Lincoln and Claiborne Parishes, Louisiana for $320 million before customary closing adjustments. Proceeds from the sale were recorded as a reduction to the carrying value of our full cost pool with no gain or loss recorded. The transaction had an effective date of January 1, 2010. In conjunction with the closing, we deposited $75 million with a qualified intermediary to facilitate like-kind exchange transactions. At June 30, 2010, we had $57.2 million remaining for use in future acquisitions.

On April 30, 2010, we completed the sale of our interest in the West Edmond Hunton Lime Unit (WEHLU) Field in Oklahoma County, Oklahoma for $155 million before customary closing adjustments. Proceeds from the sale were recorded as a reduction to the carrying value of our full cost pool with no gain or loss recorded. The transaction had an effective date of April 1, 2010. In conjunction with the closing, we assigned 5 natural gas swaps and 5 crude oil swaps to one of the purchasers.

During the first six months of 2010, we sold our interests in various non-core properties for aggregate proceeds of approximately $38 million. Proceeds from the sales were recorded as a reduction to the carrying value of our full cost pool with no gain or loss recorded.

On February 10, 2010, we sold our Talihina properties in Latimer County, Oklahoma to Ward Energy, LLC for $17 million, subject to customary closing adjustments. The effective date of the sale was December 1, 2009.

On October 30, 2009, we sold our Permian Basin properties for $376 million in cash, before customary closing adjustments. Proceeds from the sale were recorded as a reduction to the carrying value of our full cost pool with no gain or loss recorded. In conjunction with the closing of this sale, we deposited the remaining net proceeds of $331 million with a qualified intermediary to facilitate potential like-kind exchange transactions ($37.6 million was previously received as a deposit).

Financing Activities. Net cash flows provided by financing activities were $1.1 billion for the six months ended June 30, 2011. Net cash flows used in financing activities were $226.8 million for the six months ended June 30, 2010.

On May 20, 2011, we issued $600 million aggregate principal amount of our 6.25% senior notes due 2019 (the 2019 Notes). The net proceeds from the sale of the 2019 Notes were approximately $589 million, after deducting offering fees and expenses. A portion of the proceeds from the 2019 Notes were utilized to repay borrowings outstanding under our senior revolving credit facility and for working capital for general corporate purposes.

On January 31, 2011, we completed the issuance of an additional $400 million aggregate principal amount of our 7.25% senior notes due 2018. The additional 2018 Notes are a subsequent aggregate principal issue of our outstanding 7.25% senior notes due 2018 which were issued in an aggregate principal amount of $825 million on August 17, 2010, the initial 2018 Notes. 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 our 7.125% $275 million senior notes due 2012 on March 17, 2011.

During the six months ended June 30, 2011, we capitalized approximately $24.9 million of certain direct costs associated with the issuance of our long-term debt. We capitalized approximately $10.9 million in costs associated with the issuance of the 2019 Notes. We capitalized approximately $7.4 million of debt issuance costs in conjunction with the issuance of the additional 2018 Notes. We also capitalized approximately $6.6 million of direct costs associated with the amendments to our Senior Credit Agreement.

Capital financing and excess cash flow from operations are used to repay borrowings under our Senior Credit Agreement to the extent available. During the first six months of 2011, we had net borrowings under our Senior Credit Agreement of $413 million. During the first six months of 2010, we had net repayments of borrowings of $223.8 million under our Senior Credit Agreement.

We have no material changes in our long-term commitments associated with our capital expenditure plans or operating agreements other than those described below. Our level of capital expenditures will vary in future periods depending on the success we experience in our acquisition, development and exploration activities, oil and natural gas price conditions and other related economic factors. Currently no sources of liquidity or financing are provided by off-balance sheet arrangements

or transactions with unconsolidated, limited-purpose entities. The following table summarizes our contractual obligations and commitments as of June 30, 2011:

Included in our gathering and transportation commitments is our obligation to deliver to KinderHawk agreed upon minimum annual quantities of natural gas from our operated wells producing from the Haynesville and Lower Bossier Shales, within specified acreage in Northwest Louisiana through May 2015, or in the alternative, pay an annual true-up fee to KinderHawk if such minimum annual quantities are not delivered. Our obligation to deliver minimum annual quantities of natural gas to KinderHawk through May 2015 remains in effect following the sale of our remaining 50% membership interest in KinderHawk on July 1, 2011.The minimum annual quantities per contract year are as follows:

These quantities represent 50% of our anticipated production from the specified acreage at the time we entered into the contract. Production from this acreage has been significantly in excess of these quantities during 2010 and through the second quarter of 2011, and we have not been obligated to pay a true-up fee to date.

We pay KinderHawk negotiated gathering and treating fees, subject to an annual inflation adjustment factor. The gathering fee is currently equal to $0.34 per thousand cubic feet (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, our true-up fee obligation would be determined by subtracting the volumes 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 2011 were 50 Bcf less than the minimum annual quantity for such year and the year-end gathering fee was $0.34 per Mcf and the average treating fee for the period was $0.345 per Mcf, the true-up fee would be $34.3 million.

Our discussion and analysis of our financial condition and results of operations are based upon the unaudited condensed consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. Preparation of these unaudited condensed consolidated financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. There have been no material changes to our critical accounting policies from those described in our Annual Report on Form 10-K for the year ended December 31, 2010.

We reported income from continuing operations, net of income taxes of $104.9 million for the three months ended June 30, 2011 compared to income from continuing operations, net of income taxes of $14.0 million for the same period in 2010, resulting in a net change of $90.9 million. The following table summarizes key items of comparison and their related change for the periods indicated.

For the three months ended June 30, 2011, oil and natural gas revenues increased $203.9 million from the same period in 2010, to $443.7 million. The increase was primarily due to the increase in our production of 28,885 Mmcfe, or 51% over the three months ended June 30, 2010, resulting from our drilling successes in resource plays in Louisiana and Texas. Increased production contributed approximately $122 million in revenues for the three months ended June 30, 2011. Also contributing to this increase was an increase of $0.93 per Mcfe in our realized average price to $5.14 per Mcfe from $4.21 per Mcfe in the prior year period. The increase in realized average prices led to an increase in oil and natural gas revenues of approximately $82 million.

We had marketing revenues of $149.5 million and marketing expenses of $161.0 million for the three months ended June 30, 2011, resulting in a loss before taxes of $11.5 million as compared to a loss before taxes of $10.0 million for the same period in 2010. Our marketing subsidiary purchases and sells our own and third party natural gas produced from wells which we and third parties operate. We report the revenues and expenses related to these marketing activities on a gross basis as part of our operating revenues and operating expenses. Marketing revenues are recorded at the time natural gas is physically delivered to third parties at a fixed or index price. Marketing expenses attributable to gas purchases are recorded as we take physical title to the natural gas and transport the purchased volumes to the point of sale. Our loss before income taxes for the three months ended June 30, 2011 is primarily attributable to decreased margins and the amortization of our acquired transportation contracts.

We had gross revenues from our midstream segment of $6.0 million for the three months ended June 30, 2011 compared to the same period in 2010 of $16.9 million, a decrease of $10.9 million. Gross revenues of $6.0 million included $4.1 million of inter-segment revenues that were eliminated in consolidation. On a net basis, we had revenues of $1.9 million for the three months ended June 30, 2011, a decrease of $2.1 million from the prior year. Gathering and treating throughput decreased 15.1 Bcf to 15.5 Bcf for the three months ended June 30, 2011 compared to 30.6 Bcf for the three months ended June 30, 2010, which includes 25.7 Bcf of Haynesville throughput. The decrease in revenues and throughput was primarily due to the contribution of our gas gathering systems and treating facilities in the Haynesville Shale to KinderHawk on May 21, 2010.

Lease operating expenses decreased $2.7 million for the three months ended June 30, 2011 primarily due to our continued cost control efforts as well as the sale of our higher cost properties in 2010. On a per unit basis, lease operating expenses decreased $0.13 per Mcfe to $0.16 per Mcfe in 2011 from $0.29 per Mcfe in 2010. The decrease on a per unit basis is primarily due to the increase in production during 2011 from our resource plays which historically have a lower per unit operating cost. Additionally, the sale of our Terryville, WEHLU, and Fayetteville Shale properties in 2010, contributed to a decrease in costs for the three months ended June 30, 2011 over the same period in 2010 as these properties historically operated with higher operating costs per unit.

Workover expenses increased $2.7 million for the three months ended June 30, 2011 compared to the same period in 2010. The increase was primarily due to an increase in activity in the Haynesville Shale related to the treatment of corrosion.

Taxes other than income increased $11.7 million for the three months ended June 30, 2011 as compared to the same period in 2010. The largest components of taxes other than income are production and severance taxes which are generally assessed as either a fixed rate based on production or as a percentage of gross oil and natural gas sales. Our increase in production in the current year was partially offset by severance tax refunds related to drilling incentives for horizontal wells in the Haynesville and Eagle Ford Shales. For the three months ended June 30, 2011, we recorded severance tax refunds totaling $3.1 million compared to $10.1 million in the prior year. On a per unit basis, excluding the severance tax refunds, taxes other than income decreased $0.04 per Mcfe to $0.23 per Mcfe compared to $0.27 per Mcfe in 2010. This adjusted decrease from the prior year comparable

period is due to severance tax exemptions related to the drilling incentives as well as a reduction in the Louisiana statutory severance tax rate.

Gathering, transportation and other expense attributable to our oil and natural gas production segment increased $34.0 million, for the three months ended June 30, 2011 as compared to the same period in 2010. The increase was primarily due to the formation of KinderHawk on May 21, 2010, as gathering and treating fees now paid to KinderHawk historically had been paid to Hawk Field Services and eliminated in consolidation. We pay $0.34 per Mcf of gas that is delivered at KinderHawk's receipt points for gathering and a treating fee that ranges between $0.030 per Mcf and $0.365 per Mcf or more depending on carbon dioxide content. On a per unit basis, gathering, transportation and other expenses increased $0.22 per Mcfe to $0.75 per Mcfe in 2011 compared to $0.53 per Mcfe in 2010. The increase on a per unit basis is also primarily attributable to the gathering and treating fees we are paying to KinderHawk which historically had been eliminated in consolidation.

Gathering, transportation and other expenses attributable to our midstream segment decreased $0.4 million for the three months ended June 30, 2011 compared to the same period in 2010. The decrease was primarily due to the contribution of the gas gathering systems and treating facilities in the Haynesville Shale to KinderHawk on May 21, 2010, partially offset by the current year expansion of our Eagle Ford gathering and treating system.

General and administrative expense for the three months ended June 30, 2011 increased $5.9 million as compared to the same period in 2010. The increase is primarily attributable to an approximate $5.8 million increase in payroll and employee costs, including salaries, benefits and incentives associated with increases in our work force as a result of our continued growth. Professional fees increased $4.0 million over the same period in 2010. These increases were partially offset by a $5.5 million decrease in advisory service fees paid in conjunction with the KinderHawk transactions.

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 $91.0 million for the three months ended June 30, 2011 from the same period in 2010, to $189.1 million. On a per unit basis, depletion expense increased $0.48 per Mcfe to $2.20 per Mcfe. The increase on a per unit basis is primarily due to our 2010 asset sales as well as the impact of our 2010 and 2011 capital expenditures program.

Depreciation expense associated with our gas gathering systems increased $0.9 million to $1.4 million for the three months ended June 30, 2011. The increase was primarily due to the current year expansion of our Eagle Ford Shale gas gathering system partially offset by the contribution of the gas gathering systems and treating facilities in the Haynesville Shale to KinderHawk which resulted in a $404 million decrease in gas gathering system and equipment assets. We depreciate our gas gathering systems over a 30 year useful life and begin depreciating on the estimated placed in service date.

On May 21, 2010, we contributed our Haynesville Shale gathering and treating business to KinderHawk in exchange for a 50% membership interest in KinderHawk and approximately $917 million in cash. At May 21, 2010, as a result of this transaction, we recorded a deferred gain of approximately $719.4 million for the difference between 50% of the net carrying value of the assets we contributed to KinderHawk and the net cash proceeds received from KinderHawk, representing the cash contributed by Kinder Morgan at closing for its 50% membership interest in KinderHawk. We recognize the portion of the deferred gain equal to our capital commitment as contributions to KinderHawk are made or upon expiration of the capital commitment at December 31, 2011. We recognized $46.5 million and $64.4 million of the deferred gain during the three months ended June 30, 2011 and 2010, respectively.

We enter into derivative commodity instruments to economically hedge our exposure to price fluctuations on our anticipated oil, natural gas, and natural gas liquids production. Historically, we have also entered into interest rate swaps to mitigate exposure to market rate fluctuations by converting variable interest rates (such as those on our Senior Credit Agreement) to fixed interest rates. Consistent with the prior year, we have elected not to designate any positions as cash flow hedges for accounting purposes, and accordingly, we recorded the net change in the mark-to-market value of these derivative contracts in the unaudited condensed consolidated statement of operations. At June 30, 2011, we had a $192.9 million derivative asset, $154.3 million of which was classified as current, and a $30.9 million derivative liability, $16.1 million of which was classified as current. We recorded a net derivative gain of $83.5 million ($31.1 million net unrealized gain and $52.4 million net gain for cash received on settled contracts) for the three months ended June 30, 2011 compared to a net derivative loss of $16.6 million ($87.4 million net unrealized loss and a $70.8 million net gain for cash received on settled contracts) in the same period in 2010.

Interest expense and other increased $5.5 million for the three months ended June 30, 2011 compared to the same period in 2010. The increase is primarily related to the issuance of our 6.25% $600 million senior notes in the second quarter of 2011. In addition we had increased borrowings on our Senior Credit Agreement during the second quarter of 2011 compared to the same period in the prior year.

Our investment in KinderHawk in which we do not have a majority interest, but do have significant influence, is accounted for under the equity method. Under the equity method of accounting, our share of net income (loss) from KinderHawk is reflected as an increase (decrease) in our investment account and is also recorded as equity investment income (loss). Distributions from KinderHawk are recorded as reductions of our investment and contributions to KinderHawk are recorded as increases of our investment. Our net share of KinderHawk's earnings or losses is reported as "Equity investment income" in the unaudited condensed consolidated statements of operations. For the three months ended June 30, 2011, our net share of KinderHawk's income was $17.3 million compared to $2.0 million of net income for the same period in the prior year.

We had an income tax provision of $64.7 million for the three months ended June 30, 2011 due to our income from continuing operations before income taxes of $169.5 million compared to an income tax provision of $8.7 million due to our income from continuing operations before income taxes of $22.8 million in the prior year. The effective tax rate for the three months ended June 30, 2011 was 38.1% compared to 38.4% for the three months ended June 30, 2010.

We reported income from continuing operations, net of income taxes of $106.1 million for the six months ended June 30, 2011 compared to income from continuing operations, net of income taxes of $170.3 million for the same period in 2010, resulting in a decrease of $64.2 million. The following table summarizes key items of comparison and their related change for the periods indicated.

For the six months ended June 30, 2011, oil and natural gas revenues increased $253.5 million from the same period in 2010, to $793.9 million. The increase was primarily due to the increase in our production of 46,971 Mmcfe, or 42% over the six months ended June 30, 2010, resulting from our drilling successes in resource plays in Louisiana and Texas. Increased production contributed approximately $224 million in revenues for the six months ended June 30, 2011. Also contributing to this increase was an increase of $0.17 per Mcfe in our realized average price to $4.94 per Mcfe from $4.77 per Mcfe in the prior year period. The increase in realized average prices led to an increase in oil and natural gas revenues of approximately $29.5 million.

We had marketing revenues of $290.0 million and marketing expenses of $315.9 million for the six months ended June 30, 2011, resulting in a loss before taxes of $25.9 million as compared to a loss before taxes of $16.4 million for the same period in 2010. Our marketing subsidiary purchases and sells our own and third party natural gas produced from wells which we and third parties operate. We report the revenues and expenses related to these marketing activities on a gross basis as part of our operating revenues and operating expenses. Marketing revenues are recorded at the time natural gas is physically delivered to third parties at a fixed or index price. Marketing expenses attributable to gas purchases are recorded as we take physical title to the natural gas and transport the purchased volumes to the point of sale. Our loss before income taxes for the six months ended June 30, 2011 is primarily attributable to decreased margins and the amortization of our acquired transportation contracts.

We had gross revenues from our midstream segment of $10.0 million for the six months ended June 30, 2011 compared to the same period in 2010 of $46.1 million, a decrease of $36.1 million. Gross revenues of $10.0 million included $7.2 million of inter-segment revenues that were eliminated in consolidation. On a net basis, we had revenues of $2.8 million for the six months ended June 30, 2011, a decrease of $8.2 million from the prior year. Gathering and treating throughput decreased 54.0 Bcf to 27.0 Bcf for the six months ended June 30, 2011 compared to 81.0 Bcf for the six months ended June 30, 2010, which includes 71.1 Bcf of Haynesville throughput. The decrease in revenues and throughput was primarily due to the contribution of our gas gathering systems and treating facilities in the Haynesville Shale to KinderHawk on May 21, 2010.

Lease operating expenses decreased $7.4 million for the six months ended June 30, 2011 primarily due to our continued cost control efforts as well as the sale of our higher cost properties in 2010. On a per unit basis, lease operating expenses decreased $0.14 per Mcfe to $0.16 per Mcfe in 2011 from $0.30 per Mcfe in 2010. The decrease on a per unit basis is primarily due to the increase in production during 2011 from our resource plays which historically have a lower per unit operating cost. Additionally, the sale of our Terryville, WEHLU, and Fayetteville Shale properties in 2010, contributed to a decrease in costs for the six months ended June 30, 2011 over the same period in 2010 as these properties historically operated with higher operating costs per unit.

Workover expenses increased $5.2 million for the six months ended June 30, 2011 compared to the same period in 2010. The increase was primarily due to an increase in activity in the Haynesville Shale related to the treatment of corrosion.

Taxes other than income increased $10.6 million for the six months ended June 30, 2011 as compared to the same period in 2010. The largest components of taxes other than income are production and severance taxes which are generally assessed as either a fixed rate based on production or as a percentage of gross oil and natural gas sales. Our increase in production in the current year was partially offset by severance tax refunds related to drilling incentives for horizontal wells in the Haynesville and Eagle Ford Shales. For the six months ended June 30, 2011, we recorded severance tax refunds totaling $7.1 million compared to $17.8 million in the prior year. On a per unit basis, excluding the severance tax refunds, taxes other than income decreased $0.09 per Mcfe to $0.22 per Mcfe compared to $0.31 per Mcfe in 2010. This adjusted decrease from the prior year is due to severance tax

exemptions related to the drilling incentives as well as a reduction in the Louisiana statutory severance tax rate.

Gathering, transportation and other expense attributable to our oil and natural gas production segment increased $63.2 million, for the six months ended June 30, 2011 as compared to the same period in 2010. The increase was primarily due to the formation of KinderHawk on May 21, 2010, as gathering and treating fees now paid to KinderHawk historically had been paid to Hawk Field Services and eliminated in consolidation. We pay $0.34 per Mcf of gas that is delivered at KinderHawk's receipt points for gathering and a treating fee that ranges between $0.030 per Mcf and $0.365 per Mcf or more depending on carbon dioxide content. On a per unit basis, gathering, transportation and other expenses increased $0.26 per Mcfe to $0.72 per Mcfe in 2011 compared to $0.46 per Mcfe in 2010. The increase on a per unit basis is also primarily attributable to the gathering and treating fees we are paying to KinderHawk which historically had been eliminated in consolidation.

Gathering, transportation and other expenses attributable to our midstream segment decreased $4.9 million for the six months ended June 30, 2011 compared to the same period in 2010. The decrease was primarily due to the contribution of the gas gathering systems and treating facilities in the Haynesville Shale to KinderHawk on May 21, 2010, partially offset by the current year expansion of our Eagle Ford gathering and treating system.

General and administrative expense for the six months ended June 30, 2011 increased $11.2 million as compared to the same period in 2010. The increase is primarily attributable to an approximate $14.0 million increase in payroll and employee costs, including salaries, benefits and incentives associated with increases in our work force as a result of our continued growth. In addition, office-related expenses increased $1.4 million over the prior year comparable period. These increases were partially offset by a $5.5 million decrease in advisory service fees paid in conjunction with the KinderHawk transactions. These increases were also offset by a $2.0 million decrease in professional fees, primarily decreases in legal fees and settlements.

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 $144.2 million for the six months ended June 30, 2011 from the same period in 2010, to $342.6 million. On a per unit basis, depletion expense increased $0.39 per Mcfe to $2.14 per Mcfe. The increase on a per unit basis is primarily due to our 2010 asset sales as well as the impact of our 2010 and 2011 capital expenditures program.

Depreciation expense associated with our gas gathering systems decreased $0.9 million to $2.5 million for the six months ended June 30, 2011. The decrease was primarily due to the contribution of the gas gathering systems and treating facilities in the Haynesville Shale to KinderHawk which resulted in a $404 million decrease in gas gathering system and equipment assets partially offset by the current year expansion of our Eagle Ford Shale gas gathering and treating system. We depreciate our gas gathering systems over a 30 year useful life and begin depreciating on the estimated placed in service date.

recognized $95.0 million and $64.4 million of the deferred gain during the six months ended June 30, 2011 and 2010, respectively.

We enter into derivative commodity instruments to economically hedge our exposure to price fluctuations on our anticipated oil, natural gas, and natural gas liquids production. Historically, we have also entered into interest rate swaps to mitigate exposure to market rate fluctuations by converting variable interest rates (such as those on our Senior Credit Agreement) to fixed interest rates. Consistent with the prior year, we have elected not to designate any positions as cash flow hedges for accounting purposes, and accordingly, we recorded the net change in the mark-to-market value of these derivative contracts in the unaudited condensed consolidated statement of operations. At June 30, 2011, we had a $192.9 million derivative asset, $154.3 million of which was classified as current, and a $30.9 million derivative liability, $16.1 million of which was classified as current. We recorded a net derivative gain of $32.6 million ($83.9 million net unrealized loss and $116.5 million net gain for cash received on settled contracts) for the six months ended June 30, 2011 compared to a net derivative gain of $198.1 million ($102.7 million net unrealized gain and a $95.4 million net gain for cash received on settled contracts) in the same period in 2010.

Interest expense and other increased $9.4 million for the six months ended June 30, 2011 compared to the same period in 2010. The increase is primarily related to the issuance of $600 million of our 6.25% senior notes due 2019 on May 20, 2011. In addition, we had increased borrowings on our Senior Credit Agreement during the six months ended June 30, 2011 compared to the same period in the prior year.

Our investment in KinderHawk in which we do not have a majority interest, but do have significant influence, is accounted for under the equity method. Under the equity method of accounting, our share of net income (loss) from KinderHawk is reflected as an increase (decrease) in our investment account and is also recorded as equity investment income (loss). Distributions from KinderHawk are recorded as reductions of our investment and contributions to KinderHawk are recorded as increases of our investment. Our net share of KinderHawk's earnings or losses is reported as "Equity investment income" in the unaudited condensed consolidated statements of operations. For the six months ended June 30, 2011, our net share of KinderHawk's income was $30.9 million compared to $2.0 million of net income for the same period in the prior year.

We had an income tax provision of $65.2 million for the six months ended June 30, 2011 due to our income from continuing operations before income taxes of $171.3 million compared to an income tax provision of $108.0 million due to our income from continuing operations before income taxes of $278.3 million in the prior year. The effective tax rate for the six months ended June 30, 2011 was 38.1% compared to 38.8% for the six months ended June 30, 2010.

We discuss recently adopted and issued accounting standards in Item 1. Condensed Consolidated Financial Statements (Unaudited)—Note 1, "Financial Statement Presentation."

We are exposed to various risks including energy commodity price risk. When oil, natural gas, and natural gas liquids prices decline significantly our ability to finance our capital budget and operations could be adversely impacted. We expect energy prices to remain volatile and unpredictable, therefore we have designed a risk management policy which provides for the use of derivative instruments to provide partial protection against declines in oil, natural gas and natural gas liquids prices by reducing the risk of price volatility and the affect it could have on our operations. The types of derivative

instruments that we typically utilize include collars, swaps, and puts. The total volumes which we hedge through the use of our derivative instruments varies from period to period, however, generally our objective is to hedge approximately 65% to 70% of our current and anticipated production for the next 12 to 36 months. Our hedge policies and objectives may change significantly as commodities prices or price futures change.

We are exposed to market risk on our open derivative contracts of non-performance by our counterparties. We do not expect such non-performance because our contracts are with major financial institutions with investment grade credit ratings. Each of the counterparties to our derivative contracts is a lender in our Senior Credit Agreement. We did not post collateral under any of these contracts as they are secured under the Senior Credit Agreement. Please refer to Item 1. Condensed Consolidated Financial Statements (Unaudited)—Note 8, "Derivatives" for additional information.

We have also been exposed to interest rate risk on our variable interest rate debt. If interest rates increase, our interest expense would increase and our available cash flow would decrease. Periodically, we may utilize interest rate swaps to reduce the exposure to market rate fluctuations by converting variable interest rates to fixed interest rates. At June 30, 2011, we did not have any open positions that converted our variable interest rate debt to fixed interest rates. We continue to monitor our risk exposure as we incur future indebtedness at variable interest rates and will look to continue our risk management policy as situations present themselves.

We account for our derivative activities under the provisions of ASC 815, Derivatives and Hedging (ASC 815). ASC 815 establishes accounting and reporting that every derivative instrument be recorded on the balance sheet as either an asset or liability measured at fair value. See Item 1. Condensed Consolidated Financial Statements (Unaudited)—Note 8, "Derivatives" for more details.

We are exposed to market risk related to adverse changes in interest rates. Our interest rate risk exposure results primarily from fluctuations in short-term rates, which are LIBOR and ABR based and may result in reductions of earnings or cash flows due to increases in the interest rates we pay on these obligations.

At June 30, 2011, total long-term debt was $3.8 billion, of which approximately 85% bears interest at a weighted average fixed interest rate of 7.8% per year. The remaining 15% of our total debt balance at June 30, 2011 bears interest at floating or market interest rates that at our option are tied to prime rate or LIBOR. Fluctuations in market interest rates will cause our annual interest costs to fluctuate. At June 30, 2011, the interest rate on our variable rate debt was 2.8% per year. If the balance of our variable rate debt at June 30, 2011 were to remain constant, a 10% change in market interest rates would impact our cash flow by approximately $0.4 million per quarter.

In accordance with Exchange Act Rule 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and our Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of June 30, 2011 to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission's rules and forms. Our disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

There were no changes in the Company's internal control over financial reporting that occurred during the most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting.

From time to time, we may be a plaintiff or defendant in a pending or threatened legal proceeding arising in the normal course of our business. While the outcome and impact of currently pending legal proceedings cannot be determined, our management and legal counsel believe that the resolution of these proceedings through settlement or adverse judgment will not have a material effect on our consolidated operating results, financial position or cash flows.

Subsequent to our execution of the Merger Agreement discussed above, we and the members of our Board were named as defendants in purported class action lawsuits brought by our stockholders challenging the proposed transaction (the Stockholder Actions). The Stockholder Actions were filed in: the Court of Chancery of the State of Delaware, Astor BK Realty Trust v. Petrohawk Energy Corp., et al., C.A. No. 6675-CS, Grossman v. Petrohawk Energy Corp., et al., C.A. No. 6688-CS, Marina Gincherman, IRA v. Petrohawk Energy Corp., et al., C.A. No. 6700, and Binkowski v. Petrohawk Energy Corp., et al., C.A. No. 6706, and the District of Harris County, Texas, Iron Workers District Counsel of Tennessee Valley & Vicinity Pension Plan v. Petrohawk Energy Corp., et al., C.A. No. 42124, Iron Workers Mid-South Pension Fund v. Petrohawk Energy Corp., et al., C.A. No. 42590, and L.A. Murphy v. Wilson, et al., C.A. No. 42772. The Guarantor, Parent and Purchaser are named as defendants in the Grossman, Gincherman and the two Iron Workers actions, and the Guarantor and Parent are named as defendants in the Binkowski action. The Stockholder Actions seek certification of a class of our stockholders and generally allege, among other things, that: (i) each member of the Board breached his fiduciary duties in connection with the transactions contemplated by the Merger Agreement by failing to maximize stockholder value, agreeing to preclusive deal protection provisions, and failing to protect against conflicts of interest; (ii) we aided and abetted our directors' purported breaches of their fiduciary duties; and/or (iii) the Guarantor, Parent and Purchaser parties aided and abetted the purported breaches of fiduciary duties by our directors. The Stockholder Actions seek, among other relief, an injunction prohibiting the transactions contemplated by the Merger Agreement, rescission in the event such transactions are consummated, damages and attorneys' fees and costs. We believe the Stockholder Actions are without merit and intend to defend ourselves vigorously.

Under rules promulgated by the SEC, administrative or judicial proceedings arising under any Federal, State or local provisions that have been enacted or adopted regulating the discharge of materials into the environment or primarily for the purpose of protecting the environment are disclosed

if the governmental authority is a party to such proceeding and the proceeding involves potential monetary sanctions of $100,000 or more. We are not party to any such proceedings, except as described below.

We were formerly involved in natural gas exploration in the Fayetteville Shale play in North Central Arkansas. Our subsidiary, Hawk Field Services, constructed a pipeline to transport natural gas from wellheads. Hawk Field Services' activities were being performed pursuant to required environmental permits issued by the Arkansas Department of Environmental Quality and the United States Army Corps of Engineers (Corps of Engineers). The terrain in and around the Fayetteville Shale play is very hilly and required that the pipeline cross numerous small creeks and streams. Some of these streams ultimately drain into larger waters that are home to an endangered freshwater mussel known as the Speckled Pocketbook (Lampsilis streckeri).

In 2008, the United States Fish and Wildlife Service (USFWS) opened an investigation into the activities of Hawk Field Services and the Company in the Fayetteville Shale play. The investigation focused on the pipeline stream crossings and potential impacts on the Speckled Pocketbook. On April 22, 2009, we received a letter from the United States Attorney's Office for the Eastern District of Arkansas and the Environmental Crimes Section of the United States Department of Justice notifying us that we were under criminal investigation for alleged violations of the Federal Clean Water Act and the Federal Endangered Species Act with respect to the endangered Speckled Pocketbook. Hawk Field Services sold its gathering and treating assets serving the Fayetteville Shale in conjunction with the Company's disposition of its Fayetteville Shale natural gas properties and, as a consequence, neither the Company nor Hawk Field Services currently have ongoing operations in Arkansas. The Company and the United States Department of Justice have finalized a plea agreement and Hawk Field Services has pleaded guilty to three misdemeanor counts of violating the Endangered Species Act. Under the plea agreement, the Company agreed to pay a $350,000 fine and contribute $150,000 toward environmental conservation efforts in the Fayetteville Shale area. Final approval of the plea agreement is expected to occur in the summer of 2011.

There have been no material changes to the risk factors described in the Company's Annual Report on Form 10-K, for the year ended December 31, 2010, except as stated below.

Failure to complete or delays in completing our pending acquisition by affiliates of BHP Billiton could negatively affect our stock price and our future business, operations and financial results.

On July 14, 2011, we entered into an agreement and plan of merger Merger Agreement with BHP Billiton Limited, a corporation organized under the laws of Victoria, Australia, BHP Billiton Petroleum (North America) Inc., a Delaware corporation (Parent) and a wholly owned subsidiary of Guarantor, and North America Holdings II Inc., a Delaware corporation (Merger Sub) and a wholly owned subsidiary of Parent, pursuant to which Merger Sub will commence an offer (the Offer) to acquire all of the outstanding shares of our common stock, par value $0.001 per share, for $38.75 per share, net to the seller in cash, without interest. The Offer commenced on July 25, 2011 and will remain open until August 19, 2011, subject to extension under certain circumstances. The Merger Agreement also provides that following consummation of the Offer and satisfaction or waiver of certain customary conditions, Merger Sub will be merged with and into the Company, with the Company surviving as a wholly owned subsidiary of Parent. There is no assurance that Merger Sub will consummate the Offer or the merger. If the transactions contemplated by the Merger Agreement are not completed for any reason, we may be subject to a number of risks, including the following:

The pending transactions with BHP Billiton may cause disruption in our business and management and present difficulties attracting, motivating and retaining executives and other key employees.

Parties with which we do business may experience uncertainty associated with the transactions contemplated in the Merger Agreement, including with respect to current or future business relationships, and our management and employees may be distracted from day-to-day operations because matters related to the merger may require substantial commitments of time and resources. In addition, the Merger Agreement restricts us from making certain acquisitions and taking other specified actions without BHP Billiton's approval. These restrictions could prevent us from pursuing attractive business opportunities that may arise prior to the completion of the merger. These disruptions could have an adverse effect on our business, financial condition, results of operations or prospects. The adverse effect of such disruptions could be exacerbated by a delay in the consummation of the Offer and the completion of the merger or the termination of the merger agreement. In addition, uncertainty about the effect of the merger on our employees may have an adverse effect on us. This uncertainty may impair our ability to attract, retain and motivate key personnel until the merger is completed. Employee retention may be particularly challenging during the pendency of the merger, as employees may experience uncertainty about their future roles with BHP Billiton.

The Merger Agreement restricts our ability to pursue alternatives to the merger.

The Merger Agreement contains "no shop" provisions that, subject to limited fiduciary exceptions, restrict our ability to initiate, solicit, encourage or facilitate, discuss, negotiate or accept a competing third party proposal to acquire all or a significant part of us. Further, there are only a limited number of exceptions that would allow our board of directors to withdraw or change its recommendation to holders of our common stock that they tender their shares of common stock in the Offer and that stockholder vote in favor of the adoption of the merger agreement. If our board of directors were to take such actions as permitted by the merger agreement, doing so in specified situations could entitle BHP Billiton to terminate the merger agreement and to be paid a termination fee of $395.0 million. These restrictions could deter a potential acquirer from proposing an alternative transaction.

Availability of adequate gathering systems and transportation take-away capacity may hinder our access to suitable oil and natural gas markets or delay our production.

Our ability to bring natural gas, natural gas liquids and crude oil production to market depends on a number of factors including the availability and proximity of pipelines and processing facilities. The recent growth in production in the Eagle Ford Shale, especially of oil and natural gas liquids production, has limited the availability of transportation take-away capacity for these products. If we are unable to obtain adequate amounts of take-away capacity to meet our growing production levels, we may have to delay initial production or shut in our wells awaiting a pipeline connection or capacity and / or sell our production at significantly lower prices than those quoted on NYMEX or than we currently project, which could adversely affect our results of operations.

Certain federal income tax deductions currently available with respect to oil and gas exploration and development may be eliminated as a result of future legislation.

Among the changes contained in the President's Fiscal Year 2012 budget proposal, released by the White House on February 14, 2011, is the elimination or deferral of certain key U.S. federal income tax deductions currently available to oil and gas exploration and production companies. Such changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and gas properties; (ii) the elimination of current deductions for intangible drilling and development costs; (iii) the elimination of the deduction for certain U.S. production activities; and (iv) an extension of the amortization period for certain geological and geophysical expenditures. Recently, members of the U.S. Congress have considered similar changes to the existing federal income tax laws that affect oil and gas exploration and production companies, which, if enacted, would negatively affect our financial condition and results of operations. The passage of any legislation as a result of the budget proposal or any other similar change in U.S. federal income tax law could eliminate or defer certain tax deductions within the industry that are currently available with respect to oil and gas exploration and development, and any such change could negatively affect our financial condition and results of operations.

Possible regulation related to global warming and climate change could have an adverse effect on our operations and demand for oil and natural gas.

Studies over recent years have indicated that emissions of certain gases may be contributing to warming of the Earth's atmosphere. In response to these studies, governments have begun adopting domestic and international climate change regulations that requires reporting and reductions of the emission of greenhouse gases. Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of oil, natural gas and refined petroleum products, are considered greenhouse gases. Internationally, the United Nations Framework Convention on Climate Change, and the Kyoto Protocol address greenhouse gas emissions, and several counties including the European Union have established greenhouse gas regulatory systems. In the United States, at the state level, many states, either individually or through multi state regional initiatives, have begun implementing legal measures to reduce emissions of greenhouse gases, primarily through the planned development of emission inventories or regional greenhouse gas cap and trade programs or have begun considering adopting greenhouse gas regulatory programs.

The EPA has issued greenhouse gas monitoring and reporting regulations that went into effect January 1, 2010, and require reporting by regulated facilities by March 2011 and annually thereafter. In November 2010, the EPA issued a final rule requiring companies to report certain greenhouse gas emissions from oil and natural gas facilities. On July 19, 2011, the EPA amended the oil and natural gas facility greenhouse gas reporting rule to require reporting beginning in September 2012. Beyond measuring and reporting, the EPA issued an "Endangerment Finding" under section 202(a) of the Clean Air Act, concluding greenhouse gas pollution threatens the public health and welfare of current and future generations. The finding serves as a first step to issuing regulations that would require permits for and reductions in greenhouse gas emissions for certain facilities. EPA has proposed such greenhouse gas regulations and may issue final rules this year. On July 28, 2011, the EPA proposed four new regulations that, if finalized, could affect our business. The regulations would establish new source performance standards for volatile organic compounds (VOCs) and sulfur dioxide and establish an air toxic standard for oil and natural gas production, transmission, and storage. The proposed regulations would apply to wells that are hydraulically fractured, or refractured, and to storage tanks and other equipment, and limit methane emissions from those sources. The EPA is in the process of accepting public comments on the proposed regulations, and expects to take final action by February 28, 2012.

In the courts, several decisions have been issued that may increase the risk of claims being filed by governments and private parties against companies that have significant greenhouse gas emissions. Such

cases may seek to challenge air emissions permits that greenhouse gas emitters apply for and seek to force emitters to reduce their emissions or seek damages for alleged climate change impacts to the environment, people, and property.

Any laws or regulations that may be adopted to restrict or reduce emissions of greenhouse gases could require us to incur increased operating and compliance costs, and could have an adverse effect on demand for the oil and natural gas that we produce.

The following table sets forth certain information with respect to the surrender of our common stock by employees in exchange for the payment of certain tax obligations during the three months ended June 30, 2011.

The following documents are included as exhibits to this Quarterly Report on Form 10-Q. Those exhibits incorporated by reference are so indicated by the information supplied with respect thereto. Those exhibits which are not incorporated by reference are attached hereto.

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.

		June 30, 2011

		Level 1		Level 2		Level 3		Total
		(In thousands)
Assets:
	Receivables from derivative contracts	$	—	$	192,913	$	—	$	192,913

Liabilities:
	Liabilities from derivative contracts	$	—	$	30,890	$	—	$	30,890

		December 31, 2010

		Level 1		Level 2		Level 3		Total
		(In thousands)
Assets:
	Receivables from derivative contracts	$	—	$	258,739	$	—	$	258,739

Liabilities:
	Liabilities from derivative contracts	$	—	$	19,395	$	—	$	19,395


Liability for asset retirement obligation as of December 31, 2010	$	31,741
Liabilities settled and divested		(467	)
Additions		6,685
Acquisitions		36
Accretion expense		928

Liability for asset retirement obligation as of June 30, 2011	$	38,923

	Total Obligation Amount⁽¹⁾

	(in thousands)
Gathering and transportation commitments	$	2,393,253	18
Drilling rig commitments		223,850	3
Non-cancelable operating leases		31,650	8
Pipeline and well equipment obligations		155,914	1
Various contractual commitments (including, among other things, rental equipment obligations, obtaining and processing seismic data and fracture stimulation services)		57,737	3

Total commitments	$	2,862,404

	Asset derivative contracts					Liability derivative contracts

Derivatives not designated as hedging contracts under ASC 815	Balance sheet location	June 30, 2011		December 31, 2010		Balance sheet location	June 30, 2011			December 31, 2010
		(In thousands)					(In thousands)
Commodity contracts	Current assets—receivables from derivative contracts	$	154,308	$	217,018	Current liabilities—liabilities from derivative contracts	$	(16,101	)	$	(5,820	)
Commodity contracts	Other noncurrent assets—receivables from derivative contracts		38,605		41,721	Other noncurrent liabilities—liabilities from derivative contracts		(14,789	)		(13,575	)

Total derivatives not designated as hedging contracts under ASC 815		$	192,913	$	258,739		$	(30,890	)	$	(19,395	)

	June 30, 2011				December 31, 2010

Debt	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
	(In thousands)
6.25% $600 million senior notes	$	600,000	$	585,378	$	—	$	—
7.25% $1.2 billion senior notes		1,225,000		1,260,219		825,000		832,425
10.5% $600 million senior notes		600,000		679,500		600,000		684,000
7.875% $800 million senior notes		800,000		852,440		800,000		834,000
7.125% $275 million senior notes		—		—		272,375		273,465

	$	3,225,000	$	3,377,537	$	2,497,375	$	2,623,890

		Amount of gain or (loss) recognized in income on derivative contracts three months ended June 30,					Amount of gain or (loss) recognized in income on derivative contracts six months ended June 30,

	Location of gain or (loss) recognized in income on derivative contracts
Derivatives not designated as hedging contracts under ASC 815		2011		2010			2011			2010
		(In thousands)					(In thousands)
Unrealized gain (loss) on commodity contracts	Other income (expenses)—net gain (loss) on derivative contracts	$	31,056	$	(87,424	)	$	(83,909	)	$	102,671
Realized gain on commodity contracts	Other income (expenses)—net gain (loss) on derivative contracts		52,451		70,799			116,509			95,407

Total net gain (loss) on derivative contracts	Other income (expenses)—net gain (loss) on derivative contracts	$	83,507	$	(16,625	)	$	32,600		$	198,078

			June 30, 2011

					Floors			Ceilings
Period	Instrument	Commodity	Volume in Mmbtu's/ Bbl's/Gal's		Price / Price Range	Weighted Average Price		Price / Price Range	Weighted Average Price
July 2011 - December 2011	Collars	Natural gas		97,520,000	$4.75 - $6.00	$	5.53	$5.05 - $10.30	$	9.57
July 2011 - December 2011	Collars	Crude oil		1,196,000	75.00 - 80.00		78.31	95.00 - 118.00		101.82
July 2011 - December 2011	Swaps	Natural gas liquids		2,400,000	0.46		0.46
January 2012 - December 2012	Collars	Natural gas		184,830,000	4.75 - 5.00		4.86	5.70 - 8.00		6.55
January 2012 - December 2012	Swaps	Natural gas		36,600,000	5.05 - 5.20		5.16
January 2012 - December 2012	Collars	Crude oil		5,124,000	75.00 - 90.00		80.71	98.00 - 130.00		104.27
January 2013 - December 2013	Swaps	Natural gas		3,650,000	5.40		5.40

	Six Months Ended June 30,

	2011		2010
Weighted average value per option granted during the period	$	10.49	$	10.31
Assumptions⁽¹⁾:
Stock price volatility⁽²⁾		58.0%		62.0%
Risk free rate of return		2.01%		2.02%
Expected term		5.0 years		4.0 years

		June 30, 2011		December 31, 2010

		(In thousands)
Accounts receivable:
	Oil and natural gas revenues	$	199,564	$	146,823
	Marketing revenues		50,985		43,462
	Joint interest accounts		180,791		122,602
	Income and other taxes receivable		34,948		40,016
	Other		1,982		3,694

		$	468,270	$	356,597

Prepaids and other:
	Prepaid insurance	$	3,180	$	3,871
	Prepaid drilling costs		43,613		55,871
	Other		3,261		3,089

		$	50,054	$	62,831

Accounts payable and accrued liabilities:
	Trade payables	$	44,528	$	70,324
	Revenues and royalties payable		177,175		154,559
	Accrued oil and natural gas capital costs		464,461		353,280
	Accrued midstream capital costs		29,063		13,703
	Accrued interest expense		69,893		58,858
	Prepayment liabilities		23,869		42,329
	Accrued lease operating expenses		10,359		10,207
	Accrued ad valorem taxes payable		18,052		8,834
	Accrued production taxes payable		10,719		2,177
	Accrued gathering, transportation and other expenses		41,489		22,493
	Accrued employee compensation		22,373		11,401
	Other		120,394		39,073

		$	1,032,375	$	787,238

			Oil and Natural Gas			Midstream			Intersegment Eliminations			Consolidated Total

For the three months ended June 30, 2011:
	Revenues		$	593,215		$	1,865		$	—		$	595,080
	Intersegment revenues			—			4,094			(4,094	)		—

		Total revenues	$	593,215		$	5,959		$	(4,094	)	$	595,080
	Gathering, transportation and other			(68,421	)		(2,574	)		4,094			(66,901	)
	Depletion, depreciation and amortization			(191,308	)		(1,500	)		—			(192,808	)
	General and administrative			(45,800	)		(4,502	)		—			(50,302	)
	Interest (expense) income and other			(67,954	)		935			—			(67,019	)
	Amortization of deferred gain			—			46,508			—			46,508
	Equity investment income			—			17,339			—			17,339
	Income from continuing operations before income taxes		$	107,693		$	61,849		$	—		$	169,542
	Total assets		$	8,154,758		$	913,734		$	(27,859	)	$	9,040,633
	Equity investment		$	—		$	211,990		$	—		$	211,990
	Capital expenditures		$	(1,004,720	)	$	(67,239	)	$	—		$	(1,071,959	)
For the three months ended June 30, 2010:
	Revenues		$	347,172		$	3,954		$	—		$	351,126
	Intersegment revenues			—			12,896			(12,896	)		—

		Total revenues	$	347,172		$	16,850		$	(12,896	)	$	351,126
	Gathering, transportation and other			(43,185	)		(3,010	)		12,896			(33,299	)
	Depletion, depreciation and amortization			(99,326	)		(529	)		—			(99,855	)
	General and administrative			(32,374	)		(10,726	)		—			(43,100	)
	Interest (expense) income and other			(62,850	)		1,317			—			(61,533	)
	Amortization of deferred gain			—			64,367			—			64,367
	Equity investment income			—			2,047			—			2,047
	(Loss) income from continuing operations before income taxes		$	(47,144	)	$	69,897		$	—		$	22,753
	Total assets		$	6,651,621		$	816,136		$	(27,643	)	$	7,440,114
	Equity investment		$	—		$	205,453		$	—		$	205,453
	Capital expenditures		$	(572,951	)	$	(95,587	)	$	—		$	(668,538	)

			Oil and Natural Gas			Midstream			Intersegment Eliminations			Consolidated Total

For the six months ended June 30, 2011:
	Revenues		$	1,083,967		$	2,837		$	—		$	1,086,804
	Intersegment revenues			—			7,162			(7,162	)		—

		Total revenues	$	1,083,967		$	9,999		$	(7,162	)	$	1,086,804
	Gathering, transportation and other			(122,978	)		(3,980	)		7,162			(119,796	)
	Depletion, depreciation and amortization			(347,490	)		(2,630	)		—			(350,120	)
	General and administrative			(82,949	)		(7,328	)		—			(90,277	)
	Interest (expense) income and other			(135,482	)		1,660			—			(133,822	)
	Amortization of deferred gain			—			94,976			—			94,976
	Equity investment income			—			30,910			—			30,910
	Income from continuing operations before income taxes		$	48,309		$	122,984		$	—		$	171,293
	Total assets⁽¹⁾		$	8,154,758		$	913,734		$	(27,859	)	$	9,040,633
	Equity investment		$	—		$	211,990		$	—		$	211,990
	Capital expenditures		$	(1,696,537	)	$	(112,635	)	$	—		$	(1,809,172	)
For the six months ended June 30, 2010:
	Revenues		$	777,882		$	11,026		$	—		$	788,908
	Intersegment revenues			—			35,061			(35,061	)		—

		Total revenues	$	777,882		$	46,087		$	(35,061	)	$	788,908
	Gathering, transportation and other			(87,639	)		(8,877	)		35,061			(61,455	)
	Depletion, depreciation and amortization			(201,211	)		(3,412	)		—			(204,623	)
	General and administrative			(62,909	)		(12,225	)		—			(75,134	)
	Interest (expense) income and other			(126,864	)		2,485			—			(124,379	)
	Amortization of deferred gain			—			64,367			—			64,367
	Equity investment income			—			2,047			—			2,047
	Income from continuing operations before income taxes		$	188,937		$	89,342		$	—		$	278,279
	Total assets		$	6,651,621		$	816,136		$	(27,643	)	$	7,440,114
	Equity investment		$	—		$	205,453		$	—		$	205,453
	Capital expenditures		$	(1,217,323	)	$	(162,805	)	$	—		$	(1,380,128	)

Contract Year		Minimum Annual Quantity (Bcf)

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

			Three Months Ended June 30,

In thousands (except per unit and per Mcfe amounts)			2011			2010			Change
Income from continuing operations, net of income taxes			$	104,882		$	14,012		$	90,870
Operating revenues:
	Oil and natural gas			443,729			239,834			203,895
	Marketing			149,486			107,338			42,148
	Midstream			1,865			3,954			(2,089	)
Operating expenses:
	Marketing			161,049			117,309			43,740
	Production:
		Lease operating		13,726			16,384			(2,658	)
		Workover and other		4,308			1,571			2,737
Taxes other than income				16,779			5,111			11,668
Gathering, transportation and other:
	Oil and natural gas			64,327			30,289			34,038
	Midstream			2,574			3,010			(436	)
General and administrative:
	General and administrative			42,682			36,792			5,890
	Stock-based compensation			7,620			6,308			1,312
Depletion, depreciation and amortization:
	Depletion—Full cost			189,100			98,133			90,967
	Depreciation—Midstream			1,414			509			905
	Depreciation—Other			1,810			719			1,091
	Accretion expense			484			494			(10	)
Amortization of deferred gain				46,508			64,367			(17,859	)
Other income (expenses):
	Net gain (loss) on derivative contracts			83,507			(16,625	)		100,132
	Interest expense and other			(67,019	)		(61,533	)		(5,486	)
	Equity investment income			17,339			2,047			15,292
Income (loss) from continuing operations before income taxes
	Oil and natural gas			107,693			(47,144	)		154,837
	Midstream			61,849			69,897			(8,048	)
Income tax provision				(64,660	)		(8,741	)		(55,919	)
Production:
Natural gas—Mmcf				76,533			54,494			22,039
Crude oil—MBbl				986			225			761
Natural gas liquids—MBbl				559			179			380
Natural gas equivalent—Mmcfe⁽¹⁾				85,803			56,918			28,885
Average daily production—Mmcfe⁽¹⁾				943			625			318
Average price per unit⁽²⁾:
Natural gas price—Mcf			$	4.20		$	3.97		$	0.23
Crude oil price—Bbl				94.02			74.55			19.47
Natural gas liquids price—Bbl				48.56			36.30			12.26
Natural gas equivalent price—Mcfe⁽¹⁾				5.14			4.21			0.93
Average cost per Mcfe:
Production:
	Lease operating			0.16			0.29			(0.13	)
	Workover and other			0.05			0.03			0.02
Taxes other than income				0.20			0.09			0.11
Gathering, transportation and other:
	Oil and natural gas			0.75			0.53			0.22
	Midstream			0.03			0.05			(0.02	)
General and administrative:
	General and administrative			0.50			0.65			(0.15	)
	Stock-based compensation			0.09			0.11			(0.02	)
Depletion				2.20			1.72			0.48

		Average Price Paid Per Share

April 2011	5,087	$	24.56	—	—
May 2011	3,738		25.43	—	—
June 2011	2,716		25.38	—	—


	PETROHAWK ENERGY CORPORATION
Date: August 3, 2011	By:	/s/ FLOYD C. WILSON Floyd C. Wilson Chairman of the Board and Chief Executive Officer
	By:	/s/ MARK J. MIZE Mark J. Mize Executive Vice President, Chief Financial Officer and Treasurer
	By:	/s/ C. BYRON CHARBONEAU C. Byron Charboneau Vice President, Chief Accounting Officer and Controller

Exhibit No			Description

	2.1		Purchase and Sale Agreement executed May 4, 2011 by and among Petrohawk Energy Corporation, Hawk Field Services, LLC, EagleHawk Field Services LLC, KM Gathering LLC and KM Eagle Gathering LLC (Incorporated by reference to Exhibit 2.1 to our Current Report on Form 8-K filed on May 10, 2011).

	2.2		Agreement and Plan of Merger, dated as of July 14, 2011, by and among BHP Billiton Limited, BHP Billiton Petroleum (North America) Inc., North America Holdings II Inc. and Petrohawk Energy Company (Incorporated by reference to Exhibit 2.1 to our Current Report on Form 8-K filed on July 20, 2011).

	3.1		Certificate of Incorporation for Petrohawk Energy Corporation (Incorporated by reference to Exhibit 3.1 to our Form S-8 (File No. 333-117733) filed on July 29, 2004).

	3.2		Certificate of Amendment to Certificate of Incorporation for Petrohawk Energy Corporation (Incorporated by reference to Exhibit 3.1 of our Current Report on Form 8-K filed on November 24, 2004).

	3.3		Certificate of Amendment of Certificate of Incorporation of Petrohawk Energy Corporation (Incorporated by reference to Exhibit 3.1 of our Current Report on Form 8-K filed on August 3, 2005).

	3.4		Amended and Restated Bylaws of Petrohawk Energy Corporation effective as of July 12, 2006 (Incorporated by reference to Exhibit 3.2 of our Current Report on Form 8-K filed on July 17, 2006).

	3.5		Certificate of Amendment to Certificate of Incorporation of Petrohawk Energy Corporation (Incorporated by reference to Exhibit 3.1 of our Current Report on Form 8-K filed on July 17, 2006).

	3.6		Certificate of Designations of Series A Junior Preferred Stock of Petrohawk Energy Corporation effective as of October 15, 2008 (Incorporated by reference to Exhibit 3.1 of our Current Report on Form 8-K filed on October 16, 2008).

	3.7		Certificate of Amendment to Certificate of Incorporation of Petrohawk Energy Corporation (Incorporated by reference to Exhibit 3.1 of our Current Report on Form 8-K filed on June 23, 2009).

	4.1		Indenture dated as of April 8, 2004, among Mission Resources Corporation, the Guarantors named therein and The Bank of New York, as Trustee, relating to Petrohawk Energy Corporation's 9⁷/8% Senior Notes due 2011 (Incorporated by reference to Exhibit 4.1 to Mission Resources Corporation's Current Report on Form 8-K/A filed on April 15, 2004).

	4.2		First Supplemental Indenture dated as of July 28, 2005, among Petrohawk Energy Corporation, the successor by way of merger to Mission Resources Corporation, the parties named therein as Existing Subsidiary Guarantors, the parties named therein as Additional Subsidiary Guarantors, and The Bank of New York Trust Company, N.A., as successor trustee to The Bank of New York (Incorporated by reference to Exhibit 4.2 to our Current Report on Form 8-K filed on August 3, 2005).

Exhibit No			Description

	4.3		Second Supplemental Indenture dated as of July 12, 2006, among Petrohawk Energy Corporation, as successor by merger to Mission Resources Corporation, the parties named therein as subsidiary guarantors, and The Bank of New York Trust Company, N.A., as trustee (Incorporated by reference to Exhibit 4.2 of our Current Report on Form 8-K filed on July 17, 2006).

	4.4		Indenture dated April 1, 2004 among KCS Energy, Inc., U.S. Bank National Association, as trustee, and the subsidiary guarantors named therein, relating to KCS Energy, Inc.'s 7¹/8% senior notes due 2012 (Incorporated by reference to Exhibit 4.1 to KCS Energy, Inc.'s Quarterly Report on Form 10-Q filed on May 10, 2004).

	4.5		First Supplemental Indenture, dated as of April 8, 2005, to Indenture dated as of April 1, 2004, among KCS Energy, Inc., certain of its subsidiaries and U.S. Bank National Association (Incorporated by reference to Exhibit 4.1 of KCS Energy, Inc.'s Form 8-K filed on April 11, 2005).

	4.6		Second Supplemental Indenture dated July 12, 2006 among Petrohawk Energy Corporation, the successor by way of merger to KCS Energy, Inc., the parties named therein as guarantors, and U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit 4.4 to our Current Report on Form 8-K filed on July 17, 2006).

	4.7		Third Supplemental Indenture dated as of July 12, 2006 among Petrohawk Energy Corporation, the successor by way of merger to KCS Energy, Inc., the parties named therein as existing guarantors, the parties named therein as new guarantors, and U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit 4.5 to our Current Report on Form 8-K filed on July 17, 2006).

	4.8		Fourth Supplemental Indenture dated as of August 3, 2007 among Petrohawk Energy Corporation, the successor by way of merger to KCS Energy, Inc., the parties named therein as existing guarantors, the parties named therein as new guarantors, and The Law Debenture Trust Company of New York, as the successor to U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit 4.12 to our Quarterly Report on Form 10-Q filed on November 6, 2008).

	4.9		Fifth Supplemental Indenture dated as of November 28, 2008 among Petrohawk Energy Corporation, HK Energy Marketing, LLC, the parties named therein as guarantors, and The Law Debenture Trust Company of New York, as the successor to U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit 4.9 to our Annual Report on Form 10-K filed on February 25, 2009).

	4.10		Sixth Supplemental Indenture dated as of January 26, 2009 among Winwell Resources, L.L.C., KCS Resources, LLC, Petrohawk Energy Corporation, the parties named therein as guarantors, and The Law Debenture Trust Company of New York, as the successor to U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit 4.10 to our Annual Report on Form 10-K filed on February 25, 2009).

	4.11		Seventh Supplemental Indenture dated as of August 4, 2009 among Kaiser Trading, LLC, Petrohawk Energy Corporation, the existing Guarantors, and Law Debenture Trust Company of New York, as the successor to U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit 4.11 to our Quarterly Report on Form 10-Q filed on November 9, 2009).

Exhibit No			Description

	4.12		Eighth Supplemental Indenture dated as of June 30, 2010 among Big Hawk Services, LLC, Petrohawk Energy Corporation, the existing Guarantors, and Law Debenture Trust Company of New York, as the successor to U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit 4.12 to our Quarterly Report on Form 10-Q filed on August 3, 2010).

	4.13		Indenture, dated May 13, 2008, among Petrohawk Energy Corporation, the subsidiary guarantors named therein, and U.S. Bank Trust National Association (Incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed on May 15, 2008).

	4.14		First Supplemental Indenture dated as of November 28, 2008 among Petrohawk Energy Corporation, HK Energy Marketing, LLC, and parties named therein as guarantors, and U.S. Bank Trust National Association, as trustee (Incorporated by reference to Exhibit 4.17 to our Annual Report on Form 10-K filed on February 25, 2009).

	4.15		Second Supplemental Indenture dated as of January 26, 2009 among Winwell Resources, L.L.C., KCS Resources, LLC, Petrohawk Energy Corporation, the parties named therein as guarantors, and U.S. Bank Trust National Association, as trustee (Incorporated by reference to Exhibit 4.18 to our Annual Report on Form 10-K filed on February 25, 2009).

	4.16		Third Supplemental Indenture dated as of August 4, 2009 among Kaiser Trading, LLC, Petrohawk Energy Corporation, the existing Guarantors, and U.S. Bank Trust National Association, as trustee (Incorporated by reference to Exhibit 4.21 to our Quarterly Report on Form 10-Q filed on November 5, 2009).

	4.17		Fourth Supplemental Indenture dated as of June 30, 2010 among Big Hawk Services, LLC, Petrohawk Energy Corporation, the existing Guarantors, and U.S. Bank Trust National Association, as trustee (Incorporated by reference to Exhibit 4.24 to our Quarterly Report on Form 10-Q filed on August 3, 2010).

	4.18		Indenture, dated January 27, 2009, among the Petrohawk Energy Corporation, the subsidiary guarantors named therein, and U.S. Bank Trust National Association (Incorporated by reference to Exhibit 4.1 of our Current Report on Form 8-K filed on January 28, 2009).

	4.19		First Supplemental Indenture, dated August 4, 2009, among the Kaiser Trading, LLC, Petrohawk Energy Corporation, the existing Guarantors, and U.S. Bank Trust National Association, as trustee (Incorporated by reference to Exhibit 4.26 to our Quarterly Report on Form 10-Q filed on November 5, 2009).

	4.20		Second Supplemental Indenture, dated June 30, 2010, among the Big Hawk Services, LLC, Petrohawk Energy Corporation, the existing Guarantors, and U.S. Bank Trust National Association, as trustee (Incorporated by reference to Exhibit 4.19 to our Quarterly Report on Form 10-Q filed on August 3, 2010).

	4.21		Indenture, dated as of August 17, 2010, among Petrohawk Energy Corporation, the guarantors named therein and U.S. Bank National Association, as Trustee (Incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed on August 20, 2010).

	4.22		Registration Rights Agreement, dated as of August 17, 2010, among Petrohawk Energy Corporation and Barclays Capital Inc., on behalf the initial purchasers named therein (Incorporated by reference to Exhibit 4.2 to our Current Report on Form 8-K filed on August 20, 2010).

		Description

4.23		Registration Rights Agreement, dated January 31, 2011, among Petrohawk Energy Corporation, the subsidiary guarantors named therein, and the initial purchaser named therein (Incorporated by reference to Exhibit 4.2 to our Current Report on Form 8-K filed February 3, 2011).

4.24	*	Supplemental Indenture, dated May 31, 2011, among FracHawk Services, LLC, Petrohawk Energy Corporation, the existing Guarantors and U.S. Bank Trust National Association, as trustee.

4.25		Registration Rights Agreement, dated as of May 20, 2011, among Petrohawk Energy Corporation and Wells Fargo Securities, LLC, on behalf of the initial purchasers named therein (Incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed May 20, 2011).

4.26		Indenture, dated as of May 20, 2011, among Petrohawk Energy Corporation, the guarantors named therein and U.S. Bank Trust National Association, as Trustee (Incorporated by reference to Exhibit 4.2 to our Current Report on Form 8-K filed May 20, 2011).

4.27		Petrohawk Energy Corporation Fourth Amended and Restated 2004 Employee Incentive Plan (Incorporated by reference to Exhibit 4.1 to our Form S-8 (File No. 333-174824) filed on June 10, 2011)

10.1		Third Amendment to Fifth Amended and Restated Senior Revolving Credit Agreement dated April 29, 2011 (Incorporated by reference to Exhibit 10.3 of our Quarterly Report on Form 10-Q filed May 5, 2011).

10.2		Purchase Agreement dated May 17, 2011, among Petrohawk Energy Corporation, the guarantors named therein and Wells Fargo Securities, LLC, on behalf of Wells Fargo Securities, LLC, Barclays Capital Inc., BMO Capital Markets Corp., BNP Paribas Securities Corp., Goldman, Sachs & Co., J.P. Morgan Securities LLC, Merrill Lynch, Pierce, Fenner & Smith Incorporated, RBC Capital Markets, LLC, Capital One Southcoast, Inc., Credit Agricole Securities (USA) Inc., Credit Suisse Securities (USA) LLC, Deutsche Bank Securities Inc., Morgan Stanley & Co. Incorporated, UBS Securities LLC, Citigroup Global Markets Inc., ING Financial Markets LLC, KeyBanc Capital Markets Inc., Mizuho Securities USA Inc., Natixis Securities North America Inc., Scotia Capital (USA) Inc., SMBC Nikko Capital Markets Limited and SunTrust Robinson Humphrey, Inc. (Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed May 20, 2011).

10.3		Fourth Amendment to Fifth Amended and Restated Senior Revolving Credit Agreement dated July 1, 2011 (Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed July 6, 2011).

10.4	†	Executive Retention Agreement, dated as of July 14, 2011, between Petrohawk Energy Corporation and Floyd C. Wilson (Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed July 20, 2011).

10.5	†	Form of Executive Retention Agreement with Petrohawk Energy Corporation for Mark J. Mize and Ellen R. DeSanctis (Incorporated by reference to Exhibit 10.2 of our Current Report on Form 8-K filed July 20, 2011).

10.6	†	Form of Executive Retention Agreement with Petrohawk Energy Corporation for Stephen W. Herod and Charles W. Latch (Incorporated by reference to Exhibit 10.3 of our Current Report on Form 8-K filed July 20, 2011).

		Description

10.7	†	Form of Executive Retention Agreement with Petrohawk Energy Corporation for Richard K. Stoneburner and H. Weldon Holcombe (Incorporated by reference to Exhibit 10.4 of our Current Report on Form 8-K filed July 20, 2011).

10.8	†	Form of Executive Retention Agreement between the Company and David S. Elkouri, Larry L. Helm, Tina S. Obut and C. Byron Charboneau (Incorporated by reference to Exhibit 10.5 of our Current Report on Form 8-K filed July 20, 2011).

12.1	*	Computation of Ratio of Earnings to Combined Fixed Charges and Preference Dividends

31.1	*	Certificate of Chief Executive Officer under Section 302 of the Sarbanes-Oxley Act of 2002

31.2	*	Certificate of Chief Financial Officer under Section 302 of the Sarbanes-Oxley Act of 2002

32.1	*	Certifications required by Rule 13a-14(b) or Rule 15d-14(b) under the Securities Exchange Act of 1934 and 18 U.S.C. Section 1350

101	*	Interactive Data File