Edgar Filing: PETROHAWK ENERGY CORP

Form 10-Q for quarterly period ended June 30, 2007

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, 2007

Commission file number 000-25717

PETROHAWK ENERGY CORPORATION

(Exact name of registrant as specified in its charter)

Delaware

86-0876964

(State or other jurisdiction of

incorporation or organization)

(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: None

Securities registered pursuant to Section 12(g) 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

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 x No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer x Accelerated filer ¨ Non-accelerated filer ¨

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

As of August 3, 2007 the Registrant had 169,638,298 shares of Common Stock, $.001 par value, outstanding.

TABLE OF CONTENTS


		Page
PART I. FINANCIAL INFORMATION

ITEM 1.	Condensed consolidated financial statements (unaudited)	4

	Consolidated statements of operations for the three and six months ended June 30, 2007 and 2006	4

	Consolidated balance sheets as of June 30, 2007 and December 31, 2006	5

	Consolidated statements of cash flows for the six months ended June 30, 2007 and 2006	6

	Notes to condensed consolidated financial statements	7

ITEM 2.	Management’s discussion and analysis of financial condition and results of operations	20

ITEM 3.	Quantitative and qualitative disclosures about market risk	28

ITEM 4.	Controls and procedures	29

PART II. OTHER INFORMATION

ITEM 1.	Legal proceedings	29

ITEM 1A.	Risk factors	29

ITEM 2.	Unregistered sales of equity securities and use of proceeds	29

ITEM 3.	Defaults upon senior securities	29

ITEM 4.	Submission of matters to a vote of security holders	29

ITEM 5.	Other information	29

ITEM 6.	Exhibits	30

Special note regarding forward-looking statements

This report on Form 10-Q contains forward-looking statements within the meaning of the federal securities laws. These forward-looking statements may include, among others, statements reflecting the following:

•

our growth strategies;

•

anticipated trends in our business;

•

our future results of operations;

•

our ability to make or integrate acquisitions;

•

our liquidity and ability to finance our exploration, acquisition and development activities;

•

our ability to successfully and economically explore for and develop oil and natural gas resources;

•

market conditions in the oil and natural gas industry;

•

the impact of government regulation;

•

planned capital expenditures;

•

increases in oil and natural gas production;

•

our financial position, business strategy and other plans and objectives for future operations;

•

reserve and production estimates;

•

future financial performance; and

•

other matters that are discussed in our filings with the United States Securities and Exchange Commission.

We identify forward-looking statements by use of terms such as “expect,” “anticipate,” “estimate,” “plan,” “believe,” “intend,” “will,” “continue,” “potential,” “should,” “could” and similar words and expressions, although some forward-looking statements may be expressed differently. You should be aware that our actual results could differ materially from those contained in the forward-looking statements. You should consider carefully the statements under the “Risk Factors” section of this report and other sections of this report, as well as those described in the 2006 Form 10-K, as amended, which describe factors that could cause our actual results to differ from those set forth in the forward-looking statements, including, but not limited to, the following factors:

•

the possibility that the industry may be subject to future regulatory or legislative actions (including any additional taxes);

•

the volatility in commodity prices, supply of, and demand for, oil and natural gas;

•

risks associated with derivative positions;

•

the difficulty of estimating the presence or recoverability of oil and natural gas reserves and future production rates and associated costs;

•

the need for us to continually replace oil and natural gas reserves;

•

environmental risks;

•

drilling and operating risks and expense cost escalations;

•

exploration and development risks;

•

the ability of the our management to execute its plans to meet its goals;

•

our ability to retain key members of senior management and key employees;

•

general economic conditions, whether internationally, nationally or in the regional and local market areas in which we are doing business, may be less favorable than expected;

•

continued hostilities in the Middle East and other sustained military campaigns or acts of terrorism or sabotage; and

•

other economic, competitive, governmental, legislative, regulatory, geopolitical and technological factors that may negatively impact our businesses, operations or pricing.

All forward-looking statements attributable to us or persons acting on our behalf 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.

PART I. FINANCIAL INFORMATION

Item 1.

Condensed Consolidated Financial Statements (unaudited)

PETROHAWK ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(In thousands, except per share amounts)


	Three Months Ended June 30,						Six Months Ended June 30,
	2007			2006			2007			2006
Operating revenues:
Oil and gas	$	233,482		$	86,414		$	442,725		$	189,420
Operating expenses:
Production:
Lease operating		17,416			11,317			33,292			22,866
Workover and other		1,845			1,771			4,022			2,490
Taxes other than income		16,628			6,309			30,278			14,607
Gathering, transportation and other		7,599			2,264			15,023			4,136
General and administrative		16,980			8,931			32,581			15,619
Depletion, depreciation and amortization		100,210			37,458			196,048			74,908

Total operating expenses		160,678			68,050			311,244			134,626

Income from operations		72,804			18,364			131,481			54,794
Other (expenses) income:
Net gain (loss) on derivative contracts		31,591			1,644			(27,342	)		26,447
Interest expense and other		(31,789	)		(10,923	)		(62,539	)		(19,995	)

Total other (expenses) income		(198	)		(9,279	)		(89,881	)		6,452

Income before income taxes		72,606			9,085			41,600			61,246
Income tax provision		(26,975	)		(4,232	)		(15,384	)		(23,454	)

Net income		45,631			4,853			26,216			37,792
Preferred dividends		—			(109	)		—			(217	)

Net income available to common stockholders	$	45,631		$	4,744		$	26,216		$	37,575

Earnings per share of common stock:
Basic	$	0.27		$	0.06		$	0.16		$	0.45

Diluted	$	0.27		$	0.06		$	0.15		$	0.45

Weighted average shares outstanding:
Basic		167,783			83,613			167,546			82,886

Diluted		172,113			85,383			171,490			84,755

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

PETROHAWK ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS (Unaudited)

(In thousands, except share and per share amounts)


	June 30, 2007			December 31, 2006
Current assets:
Cash	$	6,097		$	5,593
Accounts receivable		151,177			155,582
Receivables from derivative contracts		31,521			68,234
Prepaid expenses and other		17,107			17,303

Total current assets		205,902			246,712

Oil and gas properties (full cost method):
Evaluated		3,430,506			2,901,649
Unevaluated		453,756			537,611

Gross oil and gas properties		3,884,262			3,439,260
Less—accumulated depletion		(572,725	)		(379,017	)

Net oil and gas properties		3,311,537			3,060,243

Other operating property and equipment:
Gross other operating property and equipment		11,528			9,542
Less—accumulated depreciation		(5,187	)		(3,742	)

Net other operating property and equipment		6,341			5,800

Other noncurrent assets:
Goodwill		935,246			938,584
Debt issuance costs, net of amortization		13,675			14,987
Receivables from derivative contracts		653			6,995
Other		5,893			6,335

Total assets	$	4,479,247		$	4,279,656

Current liabilities:
Accounts payable and accrued liabilities	$	299,121		$	295,951
Current portion of deferred income taxes		7,066			22,382
Liabilities from derivative contracts		12,407			7,986
Current portion of long-term debt		2,863			5,700

Total current liabilities		321,457			332,019

Long-term debt		1,474,583			1,326,239
Liabilities from derivative contracts		9,365			11,803
Asset retirement obligations		47,051			45,326
Deferred income taxes		661,445			633,883
Other noncurrent liabilities		2,230			2,042
Commitments and contingencies (Note 6)
Stockholders’ equity:
Common stock: 300,000,000 shares of $.001 par value value authorized; 169,628,996 and 168,486,732 shares issued and outstanding at June 30, 2007 and December 31, 2006, respectively		170			169
Additional paid-in capital		1,852,417			1,843,862
Retained earnings		110,529			84,313

Total stockholders’ equity		1,963,116			1,928,344

Total liabilities and stockholders’ equity	$	4,479,247		$	4,279,656

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

PETROHAWK ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(In thousands)


	Six Months Ended June 30,
	2007			2006
Cash flows from operating activities:
Net income	$	26,216		$	37,792
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion, depreciation and amortization		196,048			74,908
Income tax provision		15,384			23,454
Stock-based compensation		6,285			1,868
Net unrealized loss (gain) on derivative contracts		45,038			(37,591	)
Net realized (gain) loss on derivative contracts acquired		(2,429	)		9,934
Other		2,738			(375	)
Change in assets and liabilities, net of acquisitions:
Accounts receivable		2,670			16,019
Prepaid expenses and other		196			(2,782	)
Accounts payable and accrued liabilities		10,098			(18,876	)
Other		225			(810	)

Net cash provided by operating activities		302,469			103,541

Cash flows from investing activities:
Oil and gas capital expenditures		(395,548	)		(123,349	)
Acquisition of Winwell Resources, Inc., net of cash acquired of $14,965		—			(175,037	)
Acquisition of oil and gas properties		(60,345	)		(85,295	)
Proceeds received from sale of oil and gas properties		8,855			49,519
Other		(1,985	)		21,994

Net cash used in investing activities		(449,023	)		(312,168	)

Cash flows from financing activities:
Proceeds from exercise of common stock options		1,966			842
Proceeds from issuance of common stock		—			188,500
Acquisition of common stock		—			(46,200	)
Proceeds from borrowings		487,000			325,000
Repayment of borrowings		(342,838	)		(235,000	)
Net realized gain (loss) on derivative contracts acquired		2,429			(9,934	)
Offering costs		—			(10,686	)
Buyback of preferred stock		—			(4,397	)
Other		(1,499	)		(1,962	)

Net cash provided by financing activities		147,058			206,163

Net increase (decrease) in cash		504			(2,464	)
Cash at beginning of period		5,593			12,911

Cash at end of period	$	6,097		$	10,447

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

PETROHAWK ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

1. FINANCIAL STATEMENT PRESENTATION

During interim periods, Petrohawk Energy Corporation (referred to as Petrohawk or the Company) follows the same accounting policies disclosed in its 2006 Report on Form 10-K, as amended, for the preceding fiscal year with the exception of the adoption of Financial Accounting Standards Board (FASB) Financial Interpretation (FIN) No. 48, Accounting for Uncertainty in Income Taxes—an Interpretation of FASB 109 (FIN 48) as described in “Recently Issued Accounting Pronouncements” below. Please refer to the footnotes in the 2006 Form 10-K, as amended, when reviewing interim financial results.

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 results of operations for, the periods presented. Interim period results are not necessarily indicative of results of operations or cash flows for the full year.

On July 12, 2006, the Company completed its merger with KCS Energy, Inc. (KCS). Refer to Note 2, “Acquisitions and Divestitures”, for more details on the Company’s merger with KCS.

Recently Issued Accounting Pronouncements

In February 2007, the FASB issued Statement of Financial Accounting Standards (SFAS) 159, The Fair Value Option for Financial Assets and Financial Liabilities Including an Amendment of FASB Statement No. 115 (SFAS 159), which permits entities to choose to measure many financial instruments and certain other items at fair value (the Fair Value Option). Election of the Fair Value Option is made on an instrument-by-instrument basis and is irrevocable. At the adoption date, unrealized gains and losses on financial assets and liabilities for which the Fair Value Option has been elected would be reported as a cumulative adjustment to beginning retained earnings. If the Company elects the Fair Value Option for certain financial assets and liabilities, the Company will report unrealized gains and losses due to changes in fair value in earnings at each subsequent reporting date. The provisions of SFAS 159 are effective January 1, 2008. The Company is currently assessing the impact, if any, that the adoption of this pronouncement will have on the Company’s operating results, financial position or cash flows.

In September 2006, the FASB issued SFAS 157, Fair Value Measurements (SFAS 157), which defines fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements. This pronouncement applies to other standards that require or permit fair value measurements. Accordingly, this statement does not require any new fair value measurement. The provisions of SFAS 157 are effective for the Company on January 1, 2008. The Company is currently assessing the impact, if any, that the adoption of this pronouncement will have on the Company’s operating results, financial position or cash flows.

During July 2006, the FASB issued FIN 48, which addresses the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with SFAS No. 109, Accounting for Income Taxes. FIN 48 prescribes specific criteria for the financial statement recognition and measurement of the tax effects of a position taken or expected to be taken in a tax return. This interpretation also provides guidance on derecognition of previously recognized tax benefits, classification of tax liabilities on the balance sheet, recording interest and penalties on tax underpayments, accounting in interim periods, and disclosure requirements. FIN 48 is effective for fiscal periods beginning after December 15, 2006. As a result, the Company adopted FIN 48 effective January 1, 2007. The adoption of this pronouncement did not materially impact the Company’s operating results, financial position or cash flows. See “Income Taxes” below for further information.

Stock-Based Compensation

In January 2006, the Company adopted SFAS No. 123(R), Share-Based Payment (SFAS 123(R)). SFAS 123(R) revises SFAS No. 123, Accounting for Stock-Based Compensation, and focuses on accounting for share-based payments for services provided by employee to employer. The statement requires companies to expense the fair value of employee stock options and other equity-based compensation at the grant date. The statement does not require a certain type of valuation model, and either a binomial or Black-Scholes model may be used. The Company used the modified prospective application method as detailed in SFAS 123(R).

As allowed by SFAS 123(R), the Company utilizes the Black-Scholes option pricing model to measure the fair value of stock options and stock settled stock appreciation rights.

The assumptions used in the fair value method calculation for the six months ended June 30, 2007 and 2006 are disclosed in the following table:


	Six Months Ended June 30,
	2007⁽¹⁾			2006
Weighted average value per option granted during the period ⁽²⁾	$	4.41		$	4.04
Assumptions ⁽³⁾:
Stock price volatility		38.0	%		35.0	%
Risk free rate of return		4.4	%		4.4	%
Expected term		3.0	years		3.0	years

(1)

The Company’s estimated future forfeiture rate is 5%.

(2)

Calculated using the Black-Scholes fair value based method.

(3)

The Company does not pay dividends on its common stock.

Income Taxes

In July 2006, the FASB issued FIN 48, which creates a single model to address accounting for the uncertainty in income tax positions and prescribes a minimum recognition threshold a tax position must meet before recognition in the financial statements.

The evaluation of a tax position in accordance with FIN 48 is a two-step process. The first step is a recognition process to determine whether it is more likely than not that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. In evaluating whether a tax position has met the more likely than not recognition threshold, it is presumed that the position will be examined by the appropriate taxing authority with full knowledge of all relevant information. The second step is a measurement process whereby a tax position that meets the more likely than not recognition threshold is calculated to determine the amount of benefit/expense to recognize in the financial statements. The tax position is measured at the largest amount of benefit/expense that is more likely than not of being realized upon ultimate settlement.

FIN 48 allows the Company to prospectively change its accounting policy as to where interest expense and penalties on income tax liabilities are classified. The Company includes interest and penalties relating to uncertain tax positions within interest expense and other on the Company’s consolidated statement of operations.

The Company adopted the provisions of FIN 48 effective January 1, 2007 which did not have a material impact on the Company’s operating results, financial position or cash flows. The Company did not record a cumulative effect adjustment related to the adoption of FIN 48.

Included in the Company’s consolidated balance sheet at January 1, 2007 was approximately $2.1 million of liabilities associated with uncertain tax positions in the jurisdictions in which it conducts business offset by reductions to existing deferred tax liabilities. This amount included $0.1 million of accrued interest and penalties. No material amounts have been identified to date that would impact the Company’s effective tax rate. The Company does not anticipate material changes to liabilities related to such uncertain tax positions within the next twelve months.

Generally, the Company’s tax years 2003 through 2006 are either currently under audit or remain open and subject to examination by federal tax authorities or the tax authorities in Arkansas, Louisiana, New Mexico, Oklahoma and Texas, which are the most significant jurisdictions in which the Company operates. In certain of these jurisdictions, the Company operates through more than one legal entity, each of which may have different open years subject to examination. Additionally, it is important to note that years are technically open for examination until the statute of limitations in each respective jurisdiction expires.

Tax audits may be ongoing at any point in time. Tax liabilities are recorded based on estimates of additional taxes which may be due upon the conclusion of these audits. Estimates of these tax liabilities are made based upon prior experience and are updated for changes in facts and circumstances. However, due to the uncertain and complex application of tax regulations, it is possible that the ultimate resolution of audits may result in liabilities which could be materially different from these estimates.

Prospective Transactions

On June 25, 2007, the Company announced its intention to form a Master Limited Partnership (MLP) to acquire certain of its Permian and Arkoma Basin properties. The Company anticipates that the MLP will offer approximately $150 million to $225 million of partnership units to the public during the fourth quarter of 2007, subject to regulatory processes and market conditions. Petrohawk expects to control the general partner of the MLP and own a majority of the MLP.

On June 25, 2007, the Company announced its intention to sell its Gulf Coast division, and concentrate its efforts on developing and expanding the significant base of Mid-Continent natural gas resource-style assets, including tight-gas development in North Louisiana and East Texas and in the Fayetteville and Woodford Shales. The sale process for the Gulf Coast division is expected to begin during the third quarter of 2007 and closing of this transaction is anticipated in the fourth quarter of 2007.

2. ACQUISITIONS AND DIVESTITURES

Acquisitions

KCS Energy, Inc.

On April 21, 2006, the Company and KCS announced they had entered into a definitive agreement to merge the companies. This merger was consummated on July 12, 2006 and was consistent with management’s goals of acquiring properties within the Company’s core operating areas that have a significant proved reserve component and which management believes have additional development and exploration opportunities.

Upon the closing of the merger, KCS stockholders became entitled to receive a combination of $9.00 cash and 1.65 shares of Petrohawk common stock for each share of KCS common stock. At the time of the merger, there were approximately 50.0 million shares of unrestricted KCS common stock outstanding that converted into approximately 82.6 million shares of unrestricted Petrohawk common stock. Total consideration for the shares of KCS common stock was comprised of approximately $1.1 billion of Petrohawk common stock, calculated based on the five day trading average of Petrohawk’s common stock bracketing the merger announcement date, or $13.44, approximately $450 million of cash and the assumption of $275 million of KCS debt. In addition, all outstanding options to purchase KCS common stock and restricted shares of KCS common stock were converted into options to purchase the Company’s common stock or restricted shares of the Company’s common stock using an exchange ratio of approximately 2.3706 shares of Petrohawk common stock to one share of KCS common stock.

The merger was accounted for using the purchase method of accounting under the accounting standards established in SFAS No. 141, Business Combinations (SFAS 141) and No. 142, Goodwill and Other Intangible Assets (SFAS 142). As a result, the assets and liabilities of KCS were first reported in the Company’s September 30, 2006 consolidated balance sheet. The Company reflected the results of operations of KCS beginning July 12, 2006. The Company recorded the estimated fair values of the assets acquired and liabilities assumed at July 12, 2006, which primarily consisted of oil and natural gas properties of $1.6 billion, asset retirement obligations of $15.1 million, a deferred income tax liability of $421.6 million, a deferred income tax asset of $49.1 million and goodwill of $767.1 million. The deferred income tax liability recognizes the difference between the tax basis and the fair value of the acquired oil and natural gas properties. The recorded book value of the oil and natural gas properties was increased and goodwill was recorded to recognize this tax basis differential, none of which is deductible for tax purposes. The deferred income tax asset pertains to net operating loss carry-forwards and alternative minimum tax credits in the amounts of $44 million, net of tax, and $5.1 million, respectively.

Pro Forma Results of Operations for the Company’s Merger with KCS

The Company’s unaudited pro forma results of operations for the three and six months ended June 30, 2006 are presented below to illustrate the approximate pro forma effects on the Company’s results of operations under the purchase method of accounting as if the Company had completed its merger with KCS on January 1, 2006. The unaudited pro forma results of operations do not purport to represent what the results of operations would actually have been if the merger had in fact occurred on such date or to project the Company’s results of operations for any future date or period.


	Three Months Ended June 30, 2006		Six Months Ended June 30, 2006
	*(In thousands, except per share amounts)*
Pro forma:
Oil and gas revenues	$	190,745	$	402,622
Net income available to common stockholders	$	22,860	$	97,387
Basic earnings per share of common stock	$	0.14	$	0.59
Diluted earnings per share of common stock	$	0.14	$	0.58

North Louisiana Acquisitions

On January 27, 2006, the Company completed the acquisition of all of the issued and outstanding common stock of Winwell Resources, Inc. (Winwell). The aggregate consideration paid was approximately $208 million in cash after certain closing adjustments.

The Winwell acquisition was accounted for using the purchase method of accounting under the accounting standards established in SFAS 141 and SFAS 142. As a result, the assets and liabilities of Winwell were first reported in the Company’s March 31, 2006 consolidated balance sheet. The Company reflected the results of operations of Winwell beginning January 27, 2006. The Company recorded the estimated fair values of the assets acquired and liabilities assumed at January 27, 2006, which primarily consisted of oil and natural gas properties of $219.8 million, asset retirement obligations of $0.5 million, a net deferred tax liability of $78.9 million, and goodwill of $33.5 million. The deferred income tax liability recognizes the difference between the tax basis and the fair value of the acquired oil and natural gas properties. The recorded book value of the oil and natural gas properties was increased and goodwill was recorded to recognize this tax basis differential, none of which is deductible for tax purposes.

Also on January 27, 2006, the Company completed the acquisition of certain oil and natural gas assets from Redley Company (together with the Winwell acquisition, the North Louisiana Acquisitions). The aggregate consideration paid in this asset acquisition was approximately $86.1 million ($86.2 million after certain closing adjustments). The Company reflected the results of operations of the acquired assets beginning January 27, 2006. The Company deposited $15 million in earnest money in connection with the Winwell acquisition, and $7.5 million in connection with the asset acquisition. The $22.5 million in deposits were included in other non-current assets at December 31, 2005 and applied to the overall purchase price in January 2006.

Divestitures

Michigan, Wyoming and California

During the fourth quarter of 2006 the Company sold certain of its oil and natural gas assets in Michigan, Wyoming and California. The majority of these assets were acquired in the Company’s merger with KCS. Proceeds from these three separate transactions were approximately $135 million, before adjustments, and were recorded as a decrease to the Company’s full cost pool.

Gulf of Mexico

On March 21, 2006, the Company completed the sale of substantially all of its Gulf of Mexico properties for $52.5 million ($43.2 million after certain closing adjustments). These proceeds were recorded as a decrease to the Company’s full cost pool.

3. OIL AND GAS PROPERTIES

The Company uses the full cost method of accounting for its investment in oil and gas properties. Under this method of accounting, all costs of acquisition, exploration and development of oil and 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 gas properties when incurred. To the extent that capitalized costs of oil and gas properties, net of accumulated depletion exceed the discounted future net revenues of proved oil and gas reserves net of deferred taxes, such excess capitalized costs would be charged to expense. Full cost companies must use the prices in effect at the end of each accounting quarter to calculate the ceiling test value of their reserves. However, subsequent commodity price increases may be utilized to calculate the ceiling value and reserves. Decreases in product price levels, as well as changes in production rates, levels of reserves, the evaluation of costs excluded from amortization, future development costs, and service costs and other factors could result in significant future ceiling test impairments.

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.

4. LONG-TERM DEBT

Long-term debt as of June 30, 2007 and December 31, 2006 consisted of the following:


	June 30, 2007		December 31, 2006
	*(In thousands)*
Senior revolving credit facility	$	442,000	$	295,000
9 1/8% $650 million senior notes ⁽¹⁾		642,621		642,176
9 1/8% $125 million senior notes ⁽²⁾		126,262		126,338
7 1/8% $275 million senior notes ⁽³⁾		263,446		262,471
9 7/8% senior notes		254		254

	$	1,474,583	$	1,326,239

(1)

Amount includes a $7.4 million and $7.8 million discount at June 30, 2007 and December 31, 2006, respectively, recorded by the Company in conjunction with the issuance of the notes. See “9¹/8% Senior Notes” below for more details.

(2)

Amount includes a $1.3 million premium at June 30, 2007 and December 31, 2006, recorded by the Company in conjunction with the issuance of the notes. See “9¹/8% Senior Notes” below for more details.

(3)

Amount includes a $11.6 million and $12.5 million discount at June 30, 2007 and December 31, 2006, respectively, recorded by the Company in conjunction with the assumption of the notes. See “7¹/8% Senior Notes” below for more details.

Senior Revolving Credit Facility

In connection with the Company’s merger with KCS, the Company amended and restated its senior revolving credit facility. The facility provides for a $1 billion commitment with a borrowing base that will be redetermined on a semi-annual basis. The Company and the lenders each have the right to one annual interim unscheduled redetermination to adjust the borrowing base based on the Company’s oil and natural gas properties, reserves, other indebtedness and other relevant factors. At June 30, 2007, the borrowing base was $750 million. On July 25, 2007, the Company executed an amendment to its senior revolving credit facility that permits it to purchase in the open market a maximum of $375 million on the 7¹/8% Senior Notes due 2012, also referred to as the 2012 Notes and 9¹/8% Senior Notes due 2013, also referred to as the 2013 Notes. On May 8, 2007, the Company entered into an amendment to its senior revolving credit facility that would permit it to refinance the 2012 Notes. Amounts outstanding bear interest at specified margins over LIBOR of 1.00% to 1.75% for Eurodollar loans or at specified margins over ABR of 0.00% to 0.50% for ABR loans. Such margins fluctuate based on the utilization of the facility. Borrowings are secured by first priority liens on substantially all of the Company’s assets and all of the assets of, and equity interest in, the Company’s subsidiaries. Amounts drawn on the facility will mature on July 12, 2010.

The revolving credit facility contains customary financial and other covenants, including minimum working capital levels, minimum coverage of interest expense, and a maximum leverage ratio. 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, 2007, the Company was in compliance with all of its debt covenants under the revolving credit facility.

7¹/8% Senior Notes

Upon effectiveness of the Company’s merger with KCS, the Company assumed (pursuant to the Second Supplemental Indenture relating to 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. On or after April 1, 2008, the Company may redeem all or a portion of the 2012 Notes. If the notes are redeemed during any 12-month period beginning on April 1 of the year indicated below, the Company must pay 100% of the principal price, plus a specified premium (expressed as percentages of principal amount) plus accrued and unpaid interest thereon, if any, to the applicable redemption date:


Year		Percentage
2008		103.568
2009		101.784
2010		100.000
2011		100.000
2012		100.000

The 2012 Indenture contains a provision requiring the Company to offer to purchase the 2012 Notes at 101% of face value in the event of a change of control (as defined in the 2012 Indenture). Certain 2012 Note holders have alleged that the merger with KCS constituted a change of control as set forth in the 2012 Indenture. Based upon consultation with counsel, the Company does not believe that a change of control occurred. See Note 6, “Commitments and Contingencies” for more details. At June 30, 2007, the Company was in compliance with all of its debt covenants under the 2012 Notes.

In conjunction with the assumption of the 2012 Notes, 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 remaining unamortized discount is $11.6 million at June 30, 2007.

The 2012 Notes are jointly and severally and fully and unconditionally guaranteed on a senior unsecured basis by all of the Company’s subsidiaries. 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.

9¹/8% Senior Notes

On July 12, 2006 and July 27, 2006, the Company consummated private placements of $650 million and $125 million, respectively, of the 2013 Notes, pursuant to an Indenture dated as of July 12, 2006 (2013 Indenture) and First Supplemental Indenture to the 2013 Notes (the 2013 First Supplemental Indenture), among the Company, the Company’s subsidiaries named therein as guarantors, and U.S. Bank National Association, as trustee. The first tranche of $650 million in 2013 Notes were issued at 98.735% of the face amount for gross proceeds of approximately $642.0 million, before estimated offering expenses and the initial purchasers’ discount. The Company applied a portion of the net proceeds from the initial sale to fund the cash consideration paid by the Company to the KCS stockholders in connection with the Company’s merger with KCS and the Company’s repurchase of the 9⁷/8% Senior Notes due 2011 pursuant to a tender offer the Company concluded in July 2006. The additional $125 million in 2013 Notes were issued pursuant to the same Indenture at 101.125% of the face amount. The Company applied the net proceeds from the sale of the additional 2013 Notes to repay indebtedness outstanding under its senior revolving credit facility.

The 2013 Notes bear interest at the rate of 9.125% per annum, payable semi-annually on January 15 and July 15 of each year, commencing January 15, 2007. The 2013 Notes mature on July 15, 2013. The 2013 Notes are senior unsecured obligations of the Company and rank equally with all of its current and future senior indebtedness, including the 2012 Notes. The 2013 Notes rank effectively subordinate to the Company’s secured debt to the extent of the collateral, including secured debt under the revolving credit facility, and senior to any future subordinated indebtedness. The 2013 Notes are jointly and severally and fully and unconditionally guaranteed on a senior unsecured basis by all of the Company’s subsidiaries. Petrohawk Energy Corporation, the issuer of the Notes, has no material independent assets or operations apart from the assets and operations of its subsidiaries.

On or before July 15, 2009, the Company may redeem up to 35% of the aggregate principal amount of the 2013 Notes with the net cash proceeds of certain equity offerings at a redemption price of 109.13% of the principal amount plus accrued interest and unpaid interest to the redemption date provided that: (i) at least 65% in aggregate principal amount of the 2013 Notes remain outstanding immediately after the redemption; and (ii) each redemption must occur within 90 days of the date of the closing of the related equity offering.

In addition, on or before July 15, 2010, the Company may redeem all or part of the 2013 Notes, at a redemption price equal to the sum of (i) the principal amount, plus (ii) accrued and unpaid interest, if any, to the redemption date, plus (iii) the make whole premium at the redemption date.

On or after July 15, 2010, the Company may redeem some or all of the 2013 Notes at any time. If any of the 2013 Notes are redeemed during any 12-month period beginning on July 15 of the year indicated below, the Company must pay the following redemption prices (expressed as percentages of principal amount) plus accrued and unpaid interest thereon, if any, to the applicable redemption date:


Year		Percentage
2010		104.563
2011		102.281
2012		100.000

The Company may be required to offer to repurchase the 2013 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 2013 Indenture. Additionally, the Company may be required to offer to repurchase the 2013 Notes and, to the extent required by the terms thereof, all other indebtedness (as defined in the 2013 Indenture) that is pari passu with the 2013 Notes at a purchase price of 100% of the principal amount (or accreted value in the case of any such other pari passu indebtedness issued with a significant original issue discount) plus accrued and unpaid interest, if any, to the date of purchase, in the event net proceeds from assets sales are not applied as required by the 2013 Indenture.

The 2013 Indenture contains covenants that, among other things, restrict or limit the ability of the Company and its subsidiaries to: (i) borrow money; (ii) pay dividends on stock; (iii) purchase or redeem stock or subordinated indebtedness; (iv) make investments; (v) create liens; (vi) enter into transactions with affiliates; (vii) sell assets; and (viii) merge with or into other companies or transfer all or substantially all of the Company’s assets. Additionally, the 2013 Indenture covering the 2013 Notes contains a provision which provides for a rate increase of ¹/8 of one percent if the Company refinances any part of its 2012 Notes on or before July 11, 2007.

At June 30, 2007, the Company was in compliance with all of its debt covenants relating to the 2013 Notes.

In conjunction with the issuance of the $650 million 2013 Notes, the Company recorded a discount of $8.2 million to be amortized over the remaining life of the notes utilizing the effective interest rate method. The remaining unamortized discount was $7.4 million at June 30, 2007. In conjunction with the issuance of the $125 million 2013 Notes, the Company recorded a premium of $1.4 million to be amortized over the remaining life of the notes utilizing the effective interest rate method. The remaining unamortized premium was $1.3 million at June 30, 2007.

9⁷/8% Senior Notes

On April 8, 2004, Mission Resources Corporation issued $130.0 million of its 9⁷/8% 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 extinguished substantially all of its 2011 Notes for a premium of $14.9 million plus accrued interest of $3.5 million. There were approximately $0.3 million of the notes which were not redeemed and were still outstanding as of June 30, 2007. In connection with the extinguishment of substantially all of the 2011 Notes, the Company requested and received from the noteholders consent to eliminate most significant debt covenants associated with the 2011 Notes.

Debt Issuance Costs

The Company capitalizes certain direct costs associated with the issuance of long-term debt. At June 30, 2007, the Company had approximately $13.7 million of net debt issuance costs being amortized over the lives of the respective debt.

5. ASSET RETIREMENT OBLIGATIONS

If a reasonable estimate of the fair value of an obligation to perform site reclamation, dismantle facilities or plug and abandon wells can be made, the Company records a liability (an asset retirement obligation or ARO) on the consolidated balance sheet and capitalizes the asset retirement cost in oil and natural gas properties in the period in which the retirement obligation is incurred. In general, the amount of an ARO and the costs capitalized will be equal to the estimated future cost to satisfy the abandonment obligation using current prices that are escalated by an assumed inflation factor up to the estimated settlement date, which is then discounted back to the date that the abandonment obligation was incurred using an assumed cost of funds for the Company. After recording these amounts, the ARO is accreted to its future estimated value using the same assumed cost of funds and the additional capitalized costs are depreciated on a unit-of-production basis.

The Company recorded the following activity related to the ARO liability for the six months ended June 30, 2007:


	*(In thousands)*
Liability for asset retirement obligation as of December 31, 2006	$	45,326
Liabilities settled and divested		(388	)
Additions		1,219
Accretion expense		894

Liability for asset retirement obligation as of June 30, 2007	$	47,051

6. COMMITMENTS AND CONTINGENCIES

Contingencies

From time to time the Company may be a plaintiff or defendant in a pending or threatened legal proceeding arising in the normal course of its business. All known liabilities are accrued based on the Company’s best estimate of the potential loss. While the outcome and impact of currently pending legal proceedings cannot be predicted with certainty, the Company’s management and legal counsel believe that the resolution of these proceedings through settlement or adverse judgment will not have a material adverse effect on the Company’s consolidated operating results, financial position or cash flows.

In connection with the Company’s merger with KCS, it assumed by operation of law all liabilities of KCS, including the 2012 Notes, which were originally issued by KCS in April 2004. U.S. Bank National Association served as Trustee under the indenture governing the 2012 Notes (the 2012 Indenture) from and after the date of issuance until October 13, 2006, when the Company believes it resigned.

Prior to the merger, the Company carefully considered the Change of Control provisions of the 2012 Indenture and, at the consummation of the merger, the Company concluded that the transaction did not trigger a Change of Control based upon the facts and the specific language of the 2012 Indenture. Consequently, the Company did not make a Change of Control Offer within 30 days of the merger.

On September 14, 2006, Law Debenture Trust Company of New York filed suit in the Court of Chancery of the State of Delaware, New Castle County (the “Court”), against the Company, members of its board of directors, certain of its officers, KCS and certain former members of the board of directors and past management of KCS, based on the assertion that a Change of Control occurred as a consequence of the Company’s merger with KCS and requesting, among other things, that the Company offer to repurchase the 2012 Notes at 101% face value. The Company filed a motion to dismiss Law Debenture’s complaint. On December 27, 2006, Law Debenture served an amended complaint dropping all of the individual defendants from the suit and one of the claims it previously asserted against the Company and KCS. The Company moved to dismiss the amended complaint and oral argument was held on its motion to dismiss on April 17, 2007. On August 1, 2007, the Court ruled in favor of the Company and dismissed all of Law Debenture’s remaining claims.

Prior to the acquisition of Mission Resources Corporation by the Company, Mission entered into agreements with a surety company and other third parties. All parties involved agreed to be jointly and severally liable to the surety company for certain liabilities arising under the agreement and limited to approximately $35 million. This agreement was terminated during the second quarter of 2007 at no cost to the Company.

Rig Commitments

In its Form 10-K, as amended, for the year ended December 31, 2006, the Company disclosed that it had nine drilling rigs under contract for a total commitment over four years of $78.9 million. As of June 30, 2007, the Company has seven drilling rigs under contract for a total commitment over four years of $57.9 million of which $38.6 million relates to two rigs located in North Louisiana.

7. DERIVATIVE ACTIVITIES

Periodically, the Company enters into derivative commodity instruments to hedge its exposure to price fluctuations on anticipated oil and natural gas production. Under collar arrangements, if the index price rises above the ceiling price, the Company pays the counterparty. If the index price falls below the floor price, the counterparty pays the Company. Under price swaps, the Company is required to make payments to, or receive payments from, the counterparties based upon the differential between a specified fixed price and a price related to those quoted on the New York Mercantile Exchange for each respective period. Under put options, the Company pays a fixed premium to lock in a specified floor price. If the index price falls below the floor price, the counterparty pays the Company net of the fixed premium. If the index price rises above floor price, the Company pays the fixed premium. The Company does not elect hedge accounting for accounting purposes, and accordingly, recorded the net change in the mark-to-market valuation of these derivative contracts in the consolidated statement of operations.

At June 30, 2007, the Company had a $32.2 million derivative asset, $31.5 million of which is classified as current, and a $21.8 million derivative liability, $12.4 million of which is classified as current. The weighted average of the forward strip prices used to value the derivative assets and liabilities was $71.66 per barrel of oil (Bbl) and $7.80 per million British thermal unit (Mmbtu) of natural gas. The Company recorded a net derivative gain of $31.6 million ($30.0 million unrealized gain and a $1.6 million gain for cash received on settled contracts) for the three months ended June 30, 2007 and a $27.3 million net derivative loss ($45.0 million unrealized loss net of $17.7 million gain for cash received on settled contracts) for the six months ended June 30, 2007.

At December 31, 2006, the Company had a $75.2 million derivative asset, $68.2 million of which is classified as current, and a $19.8 million derivative liability, $8.0 million of which is classified as current. The weighted average of the forward strip prices used to value the derivative assets and liabilities was $65.40 per Bbl and $7.29 per Mmbtu of natural gas. The Company recorded a net derivative gain of $1.6 million and $26.4 million for the three and six months ended June 30, 2006, respectively.

Natural Gas

At June 30, 2007, the Company had the following natural gas costless collar positions:


	Collars
		Floors			Ceilings
Periods	Volume in Mmbtu’s	Price Range		Weighted Average Prices	Price Range		Weighted Average Prices
July 2007 - December 2007	29,500,000	$	5.30 - $8.00	$7.02	$	7.12 - $15.35	$11.44
January 2008 - December 2008	32,820,000		5.00 - 8.00	7.04		6.45 - 19.15	10.74

At June 30, 2007, the Company had the following natural gas swap positions:


	Swaps
Period	Volume in Mmbtu’s	Price		Weighted Average Price
July 2007 - December 2007	7,020,000	$	6.06 - $8.80	$7.95

At June 30, 2007, the Company had the following natural gas put options:


	Floors
Period	Volume in Mmbtu’s	Weighted Average Price
July 2007 - December 2007	3,640,000	$8.00

The Company has recorded a deferred premium liability of $2.9 million of long-term debt which has been classified as current at June 30, 2007 based on a weighted average deferred premium of $0.79 per Mmbtu in 2007. The natural gas put option contracts contain deferred premiums that will be paid as the contracts expire.

Crude Oil

At June 30, 2007, the Company had the following crude oil costless collar positions:


	Collars
		Floors			Ceilings
Periods	Volume in Bbls	Price Range		Weighted Average Price	Price Range		Weighted Average Price
July 2007 - December 2007	856,000	$	35.00 - $70.00	$62.99	$	43.20 - $90.10	$81.67
January 2008 - December 2008	792,000		34.00 - 70.00	64.96		45.30 - 85.05	80.26

At June 30, 2007, the Company had the following crude oil swap positions:


	Swaps
Periods	Volume in Bbls	Price		Weighted Average Price
July 2007 - December 2007	18,000	$	63.85	$63.85
January 2008 - December 2008	144,000		38.10	38.10

8. STOCKHOLDERS’ EQUITY

In conjunction with the Company’s merger with KCS on July 12, 2006, the Company issued approximately 83.8 million shares of its common stock as consideration to the former stockholders of KCS.

In connection with the North Louisiana Acquisitions, on February 1, 2006, the Company issued and sold 13.0 million shares of its common stock for $14.50 per share, for an aggregate offering amount of approximately $188.5 million. The Company received approximately $180.4 million in net proceeds from the offering. Contemporaneously with the offering, the Company agreed to repurchase, and EnCap Investments, L.P., and certain of its affiliates, agreed to sell, approximately 3.3 million shares for $46.2 million, which represents a price equal to the net proceeds received for those 3.3 million shares by the Company from the offering. The common stock was offered and sold pursuant to private placement exemptions from registration provided by Rule 506 of Regulation D, under Section 4(2) of the Act, Regulation S of the Act and similar exemptions under state law. Shares of the common stock were offered and sold only to “accredited investors” (as defined in Rule 501(a) of the Act) and non-United States persons pursuant to the offers and sales outside the United States within the meaning of Regulation S under the Act. The placement agents received a cash payment of approximately $7.7 million as compensation for services provided in connection with the offering and to reimburse them for certain expenses.

Stock Appreciation Rights

Though not utilized during 2006, the Company’s 2004 Employee Incentive Plan (the 2004 Plan) permits awards of stock appreciation rights. A stock appreciation right is similar to a stock option, in that it represents the right to realize the increase in market price, if any, of a fixed number of shares over the grant value of the right, which is equal to the market price of the Company’s common stock on the date of grant. However, to realize the value of a stock option the holder must pay the exercise price in exchange for shares of stock underlying the option, the value embodied by the stock appreciation right, if any, are settled in exchange for shares of common stock valued on the date of settlement. Stock appreciation rights vest one-third annually after the original grant date. The term is ten years from the date of grant, which is the maximum term permitted under the 2004 Plan. At the end of the term, the right to receive the value of the stock appreciation right expires.

During the six months ended June 30, 2007, the Company granted stock appreciation rights covering 1.4 million shares of common stock to employees of the Company. The stock appreciation rights have an exercise price of $11.64 and vest over a three year period at a rate of one-third on the annual anniversary date of the grant and expire ten years from the grant date. At June 30, 2007, the unrecognized compensation expense related to non-vested stock appreciation rights totaled $3.7 million and will be recognized on a straight line basis over the weighted average remaining vesting period of 2.7 years.

Stock Options

The Company did not award any stock options to employees during the six months ended June 30, 2007.

During the first six months of 2006, the Company granted stock options covering 0.9 million shares of common stock to employees of the Company. The options have exercises prices ranging from $11.43 to $16.04 with a weighted average price of $13.90. These options vest over a three year period at a rate of one-third on the annual anniversary date of the grant and expire ten years from the grant date. At June 30, 2007, the unrecognized compensation expense related to non-vested stock options totaled $2.9 million and will be recognized on a straight line basis over the weighted average remaining vesting period of 1.8 years.

Restricted Stock

During the six months ended June 30, 2007, the Company granted 0.7 million shares of restricted stock to employees of the Company. These restricted shares were granted at prices ranging from $11.64 to $12.26 with a weighted average price of $11.64.

During the first six months of 2006, the Company granted 0.3 million shares of restricted common stock to employees and non-employee directors of the Company. These restricted shares were granted at prices ranging from $11.88 to $16.04 with a weighted average price of $15.19.

Employee shares vest over a three-year period at a rate of one-third on the annual anniversary date of the grant and the non-employee directors’ shares vest six-months from the date of grant. At June 30, 2007, the unrecognized compensation expense related to non-vested restricted stock totaled $11.9 million and will be recognized on a straight line basis over the weighted average remaining vesting period of 2.1 years.

Performance Shares

In conjunction with the Company’s merger with KCS, the Company adopted a plan under which performance share awards are granted under the KCS Energy, Inc. 2005 Employee and Directors Stock Plan. Performance awards contain a contingent right to receive shares of common stock. The grantee would earn between 0% and 200% of the target amount of performance shares upon the achievement of pre-determined objectives over a three-year performance period. The objectives relate to the Company’s total stockholder return (as defined in the form of performance share agreement) as compared to the total stockholder return of a group of peer companies during the performance period. The Company does not anticipate the issuance of any additional performance share awards in future periods. The fair value of the awards using a Monte Carlo technique was $10.89 per share.

Series B Preferred Stock

In connection with the acquisition of Wynn-Crosby on November 23, 2004, the Company issued and sold 2.58 million shares of Series B 8% Automatically Convertible Preferred Stock (Series B Preferred Stock) for $77.50 per share, for an aggregate offering amount of approximately $200 million. The Company received approximately $185 million in net proceeds from the offering. The Series B Preferred Stock was offered and sold pursuant to private placement exemption from registration provided in Rule 506 of Regulation D under Section 4(2) of the Act and similar exemptions under state law.

On December 31, 2004 each outstanding share of the Series B Preferred Stock converted into ten shares of common stock. Accordingly, 2.6 million shares of the Company’s Series B Preferred Stock converted into 25.8 million shares of common stock.

9. RELATED PARTY TRANSACTIONS

In February 2006, the Company repurchased approximately 3.3 million shares of its common stock held by EnCap Investments, L.P., and certain of its affiliates (EnCap), at a price per share equal to the net proceeds per share that the Company received from a private offering of 13.0 million of its common shares that closed on the same day as the EnCap purchase. The 3.3 million shares were repurchased for $46.2 million.

10. NET EARNINGS PER COMMON SHARE

The following represents the calculation of net earnings per common share:


	Three Months Ended June 30,					Six Months Ended June 30,
	2007		2006			2007		2006
	*(In thousands, except per share amounts)*
Basic
Net income	$	45,631	$	4,853		$	26,216	$	37,792
Less: preferred dividends		—		(109	)		—		(217	)

Net (loss) income available to common stockholders	$	45,631	$	4,744		$	26,216	$	37,575

Weighted average number of shares		167,783		83,613			167,546		82,886

Basic earnings per common share	$	0.27	$	0.06		$	0.16	$	0.45

Diluted
Net income	$	45,631	$	4,744		$	26,216	$	37,575
Plus: preferred dividends		—		109			—		217

Net (loss) income available to common stockholders	$	45,631	$	4,853		$	26,216	$	37,792

Weighted average number of shares		167,783		83,613			167,546		82,886
Common stock equivalent shares representing shares issuable upon exercise of stock options		2,985		482			2,645		552
Common stock equivalent shares representing shares issuable upon exercise of warrants		1,345		1,229			1,299		1,258
Common stock equivalent shares representing shares “as-if” conversion of preferred shares		—		59			—		59

Weighted average number of shares used in calculation of diluted income per common share		172,113		85,383			171,490		84,755

Diluted earnings per common share	$	0.27	$	0.06		$	0.15	$	0.45

The following common stock equivalents were not included in the computation for diluted net earnings per common share because the exercise price exceeds fair market value:


	Three Months Ended June 30,		Six Months Ended June 30,
Common Stock Equivalents:	2007	2006	2007	2006
	*(In thousands)*
Options and stock appreciation rights	16	878	679	773
Warrants	13	18	18	18

	29	896	697	791

11. ADDITIONAL FINANCIAL STATEMENT INFORMATION

Certain balance sheet amounts are comprised of the following:


	June 30, 2007		December 31, 2006
	*(In thousands)*
Accounts receivable:
Oil and gas sales	$	101,552	$	107,003
Joint interest accounts		39,296		37,056
Income taxes receivable		6,666		5,453
Other		3,663		6,070

	$	151,177	$	155,582

Accounts payable and accrued liabilities:
Trade payables		31,041	$	31,565
Revenues and royalties payable		86,114		69,383
Accrued capital costs		102,059		111,252
Accrued interest expense		37,480		40,906
Operator prepayment liability		10,000		5,839
Accrued lease operating expenses		8,319		10,601
Accrued ad valorem taxes payable		4,741		7,086
Accrued employee compensation		5,300		2,649
Other		14,067		16,670

	$	299,121	$	295,951

Item 2.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following review of operations for the three and six months ended June 30, 2007 and 2006 should be read in conjunction with our condensed consolidated financial statements and the notes thereto included in this Form 10-Q and with the consolidated financial statements, notes and management’s discussion and analysis included in our Form 10-K, as amended, for the year-ended December 31, 2006.

Overview

We are an independent oil and natural gas company engaged in the acquisition, development, production and exploration of oil and natural gas properties located in onshore North America. Our properties are concentrated in East Texas/North Louisiana, onshore Gulf Coast, and in the Permian, Anadarko and Arkoma basins. We have increased our proved reserves and production through acquisitions and the exploitation of acquired properties. In 2006 we acquired approximately 537 billion cubic feet of natural gas equivalent (Bcfe) of proved reserves for approximately $2.2 billion in conjunction with our acquisitions in North Louisiana and our merger with KCS Energy, Inc. (KCS). In addition, we sold an estimated 80 Bcfe of proved reserves for approximately $200 million.

On June 25, 2007, we announced our intention to form a Master Limited Partnership (MLP) to acquire certain of our Permian and Arkoma Basin properties. We anticipate that the MLP will offer approximately $150 million to $225 million of partnership units to the public during the fourth quarter of 2007, subject to regulatory processes and market conditions. We expect to control the general partner of the MLP and own a majority of the MLP.

On June 25, 2007, we announced our intention to sell our Gulf Coast division, and concentrate our efforts on developing and expanding our significant base of Mid-Continent natural gas resource-style assets, including tight-gas development in North Louisiana and East Texas and in the Fayetteville and Woodford Shales. The sale process for the Gulf Coast division is expected to begin during the third quarter of 2007. At December 31, 2006, our Gulf Coast division properties contained estimated proved reserves of 663 Bcfe. At June 1, 2007, average daily production from those reserves was approximately 105 Mmcfe/d. This division is active, with a number of rigs currently drilling and a 2007 capital budget of $200 million.

In the first six months of 2007, we produced 58.5 Bcfe compared to production of 24.0 Bcfe for the comparable period of the prior year. Natural gas production was 49.6 billion cubic feet (Bcf) and oil production was 1,479 thousand barrels of oil (Mbbls) for the first six months of 2007. Natural gas equivalent production increased 34.5 Bcfe from the same period in 2006. This increase was primarily attributable to the completion of our merger with KCS in July 2006, the completion of certain acquisitions in North Louisiana, which we refer to collectively as the North Louisiana Acquisitions, in January of 2006, as well as our continued drilling success. We drilled 181 wells during the first six months of 2007, 173 of which were successful for a success rate of 96%. We reported oil and gas revenues for the six months ended June 30, 2007 of $442.7 million. This represents an increase of $253.3 million as compared to the prior year. The increase in our production and oil and natural gas revenues was principally through acquisitions complemented by our continued drilling success.

Our financial results depend upon many factors, particularly the price of oil and natural gas and our ability to market our production. Commodity prices are affected by changes in market demands, which are impacted by overall economic activity, weather, pipeline capacity constraints, inventory storage levels, basis differentials and other factors. As a result, we cannot accurately predict future oil and natural gas prices, and therefore, we cannot determine the effect increases or decreases in future prices will have on our capital program, production volumes and future revenues. Finding and developing oil and natural gas reserves at economical costs are also critical to our long-term success.

Capital Resources and Liquidity

Our sources of cash for the six months ended June 30, 2007 and 2006 were from operating and financing activities. Proceeds from the issuance of long-term debt and cash received from operations were offset by cash used in investing activities to fund our drilling program and acquisition activities, net of any divestiture activities. Operating cash flow fluctuations were substantially driven by changes in commodity prices and changes in our production volumes. Prices for oil and natural gas have historically been subject to seasonal influences 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. Working capital was substantially influenced by these variables. Fluctuation in cash flow may result in an increase or decrease in our capital and exploration expenditures. See Results of Operations below for a review of the impact of prices and volumes on sales. The formation of the MLP and Gulf Coast division sale, when completed will also have impact on the Company’s capital resources and liquidity.

Net increase (decrease) in cash is summarized as follows:


	Six Months Ended June 30,
	2007			2006
	*(In thousands)*
Cash flows provided by operating activities	$	302,469		$	103,541
Cash flows used in investing activities		(449,023	)		(312,168	)
Cash flows provided by financing activities		147,058			206,163

Net increase (decrease) in cash	$	504		$	(2,464	)

Operating Activities. Net cash provided by operating activities for the six months ended June 30, 2007 and 2006 were $302.5 million and $103.5 million, respectively. Net cash flows provided by operating activities increased in 2007 primarily due to our 143.9% increase in production volumes as a result of our recent acquisition activities as well as our continued drilling success. Also contributing to this increase was our continued success in reducing our operating costs on a per unit basis. These reductions in operating costs were partially offset by a 4.1% decrease in our realized natural gas equivalent price compared to the same period in the prior year. We expect 2007 production to increase, but we are unable to predict future commodity prices. As a result, 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 $449.0 million and $312.2 million for the six months ended June 30, 2007 and 2006, respectively.

During the first six months of 2007, we spent $395.5 million on capital expenditures in conjunction with our drilling program. We participated in the drilling of 181 wells in 2007, of which eight were dry holes, for a success rate of 96%. In 2006, we spent $123.3 million on capital expenditures in conjunction with our participation in the drilling of 130 wells.

During the first six months of 2007, we spent $60.3 million primarily to acquire additional interests in both the Elm Grove and Terryville fields, our two highest producing tight-gas fields in North Louisiana. The acquisitions at Elm Grove involve additional interest in more than 10,000 acres and additional interest in approximately 3,000 acres at Terryville. Our program to acquire additional interests and acreage in both of these key fields is ongoing.

During the first quarter of 2006, we completed the acquisition of Winwell for $208 million in cash after closing adjustments, as well as the acquisition of certain oil and gas properties for $86 million in cash after closing adjustments.

We closed the previously announced $52.5 million divestment of substantially all of our properties in the Gulf of Mexico on March 21, 2006. The net proceeds received in this transaction were used to pay down a portion of our debt facilities.

During the second quarter of 2007, we increased our capital budget to $675 million exclusive of acquisitions from $625 million to fund our drilling program. Higher revenues from increased production supported by our hedged commodity prices and revolving credit facility are expected to fund the incremental capital spending. We establish the budget for these amounts based on our current estimate of future commodity prices. Due to the volatility of commodity prices, our budget may be periodically adjusted.

Financing Activities. Net cash flows provided by financing activities were $147.1 million and $206.2 million for the six months ended June 30, 2007 and 2006, respectively. Cash flows provided by financing activities in 2007 were the result of increased borrowings, primarily to fund our drilling and acquisition activities.

In connection with the North Louisiana Acquisitions, on February 1, 2006, we issued and sold 13 million shares of our common stock for $14.50 per share, for an aggregate offering amount of approximately $188.5 million. Additionally, we repurchased approximately 3.3 million shares of common stock for $46.2 million from EnCap Investments, L.P. and certain of its affiliates. We incurred a total of $10.7 million of offering costs during the six months ended June 30, 2006.

We strive to maintain excess availability under our debt facilities. Excess cash flow and non-core asset sales are used to repay debt to the extent available. During the first six months of 2007, we had net borrowings of $144.2 million primarily due to the cash requirements of our drilling program as well as to fund our acquisition activities for the first half of 2007. During the first six months of 2006, we had net borrowings of $90 million primarily due to the funding requirements to close the North Louisiana Acquisitions.

Financing activities in 2007 and 2006 included $2.4 million of cash received and $9.9 million of cash paid on settled derivative contracts that were acquired in conjunction with our acquisition activities.

During the first six months of 2006, we paid out previously accrued fourth quarter of 2005 dividends of $0.1 million on our 8% cumulative preferred stock as well as our first and second quarter 2006 dividends of $0.1 million each. In April 2006, we initiated a buyback of this preferred stock for $9.25 per unit, resulting in a $4.4 million use of cash from financing activities.

Contractual Obligations

We have no material long-term commitments associated with our capital expenditure plans or operating agreements. Consequently, we believe we have a significant degree of flexibility to adjust the level of such expenditures as circumstances warrant. Our level of capital expenditures will vary in future periods depending on the success we experience in our acquisition, developmental and exploration activities, oil and natural gas price conditions and other related economic factors. Currently no sources of liquidity or financing are provided by off-balance sheet arrangements or transactions with unconsolidated, limited-purpose entities.

In our Form 10-K, as amended, for the year ended December 31, 2006, we disclosed that we had nine drilling rigs under contract for a total commitment over four years of $78.9 million. As of June 30, 2007, we have seven drilling rigs under contract for a total commitment over four years of $57.9 million of which $38.6 million relates to two rigs located in North Louisiana.

Critical Accounting Policies and Estimates

Our discussion and analysis of our financial condition and results of operation are based upon the condensed consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America. Preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. There have been no changes to our critical accounting policies from those described in the 2006 Form 10-K, as amended.

Results of Operations

Quarters ended June 30, 2007 and 2006

We reported net income of $45.6 million for the three months ended June 30, 2007 compared to net income of $4.8 million for the comparable period in 2006. The increase in net income of $40.8 million from the three months ended June 30, 2006, was primarily driven by the change in fair value of derivative instruments due to the change in our weighted average forward strip which resulted in a net increase of $29.9 million on derivative contracts. Also contributing to this increase was an increase in our averages equivalent sales price of $0.58 per Mcfe and an increase in production volumes of 17.7 Bcfe due to our acquisitions and successful drilling.


In thousands (except per unit and per Mcfe amounts)	Three Months Ended June 30,						Increase (Decrease)
In thousands (except per unit and per Mcfe amounts)	2007			2006			Increase (Decrease)
Net income	$	45,631		$	4,853		$	40,778
Oil and gas revenues		233,482			86,414			147,068
Expenses:
Production:
Lease operating		17,416			11,317			6,099
Workover and other		1,845			1,771			74
Taxes other than income		16,628			6,309			10,319
Gathering, transportation and other		7,599			2,264			5,335
General and administrative:
General and administrative		13,582			7,708			5,874
Stock-based compensation		3,398			1,223			2,175
Depletion, depreciation and amortization:
Depletion – Full cost		99,008			36,941			62,067
Depreciation – Other		752			278			474
Accretion expense		450			239			211
Net gain on derivative contracts		31,591			1,644			29,947
Interest expense and other		(31,789	)		(10,923	)		(20,866	)
Income tax provision		(26,975	)		(4,232	)		(22,743	)

Production:
Natural Gas – Mmcf		25,069			8,321			16,748
Crude Oil – Mbbl		731			569			162
Natural Gas Equivalent – Mmcfe		29,454			11,737			17,717
Average Daily Production – Mmcfe		324			129			195

Average price per unit *⁽¹⁾*:
Gas price per Mcf	$	7.51		$	5.80		$	1.71
Oil price per Bbl		62.07			66.86			(4.79	)
Equivalent price per Mcfe		7.94			7.36			0.58

Average cost per Mcfe:
Production:
Lease operating		0.59			0.96			(0.37	)
Workover and other		0.06			0.15			(0.09	)
Taxes other than income		0.56			0.54			0.02
Gathering, transportation and other		0.26			0.19			0.07
General and administrative:
General and administrative		0.46			0.66			(0.20	)
Stock-based compensation		0.12			0.10			0.02
Depletion		3.36			3.15			0.21

(1)

Amounts exclude the impact of cash paid on, or received from, settled contracts.

For the three months ended June 30, 2007, oil and natural gas sales increased $147.1 million, from the same period in 2006, to $233.5 million. The increase was primarily due to the increase in production of 17,717 Mmcfe primarily related to our merger with KCS. The remaining increase in volumes was due to our successful drilling program. Increased production led to a $130 million increase in revenues for the three months ended June 30, 2007. Also contributing to this increase is a higher realized average price per Mcfe of $0.58 to $7.94, which contributed additional revenue of $17.1 million.

Lease operating expenses increased $6.1 million for the three months ended June 30, 2007. The increase was primarily due to an increase in production volumes as a result of our acquisition activities, as well as our successful drilling activities in 2007. We drilled 100 gross wells during the three months ended June 30, 2007 compared to 64 gross wells in 2006. On a per unit basis, lease operating expenses decreased from $0.96 per Mcfe in 2006 to $0.59 per Mcfe in 2007. The decrease on a per unit basis is primarily due to our continued cost control efforts. Additionally, we continue to identify divestment prospects which tend to be outlying, higher operating cost properties as evident by the transactions that closed during the fourth quarter of 2006. Also contributing to the decrease on a per unit basis was our acquisition of lower cost properties in conjunction with our merger with KCS and properties acquired in the North Louisiana Acquisitions.

Taxes other than income increased $10.3 million for the three months ended June 30, 2007 as compared to the same period in 2006. The largest components of taxes other than income are production and severance taxes which are generally assessed as a percentage of gross oil and natural gas sales. As a percentage of oil and gas sales, taxes other than income remained constant at 7% in 2007 and 2006.

Gathering, transportation and other expense increased $5.3 million, or $0.07 per Mcfe, for the three months ended June 30, 2007 as compared to the same period in 2006. This increase was due to our recent acquisition activities including the completion of our merger with KCS as well as the North Louisiana Acquisitions.

General and administrative expense for the three months ended June 30, 2007 increased $5.9 million to $13.6 million compared to $7.7 million in the same period in 2006. This increase was due to our continued growth over the past two years. In 2006, we completed the North Louisiana Acquisitions as well as our merger with KCS which increased compensation and other costs associated with increased staffing levels to meet the demands of our expanding operations. General and administrative expense has decreased on a per Mcfe basis from $0.66 per Mcfe in 2006 to $0.46 per Mcfe in 2007 as production increases have exceeded our administrative expense increases.

Stock-based compensation increased $2.2 million for the three months ended June 30, 2007 as compared to the same period in the prior year. This increase was primarily related to additional stock options and restricted stock grants assumed as part of our merger with KCS in July 2006, as well as stock appreciation rights and restricted stock grants to employees during 2007.

Depletion expense increased $62.1 million for the three months ended June 30, 2007 from the same period in 2006 to $99.0 million. Depletion for oil and natural gas properties is calculated using the unit of production method, which essentially depletes the capitalized costs associated with the 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. On a per unit basis, depletion expense increased $0.21 per Mcfe to $3.36 per Mcfe from $3.15 per Mcfe. This increase was due to our merger with KCS in July 2006 and the North Louisiana Acquisitions in January 2006 which substantially increased our future development costs.

We enter into derivative commodity instruments to hedge our exposure to price fluctuations on our anticipated oil and natural gas production. 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 valuation of these derivative contracts in the consolidated statement of operations. The Company recorded a net derivative gain of $31.6 million ($30.0 million unrealized gain and a $1.6 million gain for cash received on settled contracts) for the three months ended June 30, 2007 compared to a net derivative gain of $1.6 million in the prior year. The net derivative gain for three months ended June 30, 2007 was primarily due to the change in the fair value of derivative instruments from March 31, 2007 as our weighted average forward strip price for natural gas decreased $0.67 per million British thermal unit (Mmbtu) from March 31, 2007 to June 30, 2007.

Interest expense and other increased $20.9 million for the three months ended June 30, 2007 compared to the same period in 2006. This increase was due to additional debt we incurred in conjunction with our merger with KCS in July 2006 and, to a lesser extent, the North Louisiana Acquisitions in January 2006. Also contributing to this increase was the increase of $147 million in our senior revolving credit facility during the first half of 2007. This increase was used to fund our acquisition and drilling activities, as well as other general corporate purposes.

Income tax expense for the three months ended June 30, 2007 increased $22.7 million from the prior year. The increase in income tax expense from prior year was primarily due to our pre-tax income of $72.6 million for the three months ended June 30, 2007 compared to pre-tax income of $9.1 million in 2006. The effective tax rates for the three months ended June 30, 2007 and 2006 were 37.2% and 46.6%, respectively. The decrease in our effective tax rate was primarily due to changes in state apportionment percentages due to the merger of KCS properties with historical Petrohawk properties. The 2006 rate was affected by the recognition of a change in the Texas state franchise tax rate due to a change in the tax law. In May 2006, the State of Texas enacted substantial changes to its tax structure beginning in 2007 by imposing a new tax based upon modified gross revenue referred to as the “Margin Tax.” We determined the “Margin Tax” to be an income tax as defined under Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes.

Results of Operations

Six months ended June 30, 2007 and 2006

We reported net income of $26.2 million for the six months ended June 30, 2007 compared to net income of $37.8 million for the comparable period in 2006. The decrease in net income of $11.6 million from the six months ended June 30, 2006, was primarily driven by the change in fair value of derivative instruments due to the change in our weighted average forward strip which resulted in a net decrease of $53.8 million on derivative contracts and a decrease in our averages equivalent sales price of $0.32 per Mcfe which led to a decrease of $18.7 million in our oil and gas revenues. These decreases were partially offset by an increase in production of 34.5 Bcfe due to our acquisitions and successful drilling which led to an increase of $272.0 million in our oil and gas revenues.


In thousands (except per unit and per Mcfe amounts)	Six Months Ended June 30,						Increase (Decrease)
In thousands (except per unit and per Mcfe amounts)	2007			2006			Increase (Decrease)
Net income	$	26,216		$	37,792		$	(11,576	)
Oil and gas revenues		442,725			189,420			253,305
Expenses:
Production:
Lease operating		33,292			22,866			10,426
Workover and other		4,022			2,490			1,532
Taxes other than income		30,278			14,607			15,671
Gathering, transportation and other		15,023			4,136			10,887
General and administrative:
General and administrative		26,296			13,751			12,545
Stock-based compensation		6,285			1,868			4,417
Depletion, depreciation and amortization:
Depletion – Full cost		193,708			73,692			120,016
Depreciation – Other		1,446			538			908
Accretion expense		894			678			216
Net (loss) gain on derivative contracts		(27,342	)		26,447			(53,789	)
Interest expense and other		(62,539	)		(19,995	)		(42,544	)
Income tax provision		(15,384	)		(23,454	)		8,070

Production:
Natural Gas – Mmcf		49,595			16,979			32,616
Crude Oil – Mbbl		1,479			1,165			314
Natural Gas Equivalent – Mmcfe		58,468			23,971			34,497
Average Daily Production – Mmcfe		323			132			191

Average price per unit *⁽¹⁾*:
Gas price per Mcf	$	7.17		$	6.80		$	0.37
Oil price per Bbl		59.05			63.28			(4.23	)
Equivalent price per Mcfe		7.58			7.90			(0.32	)

Average cost per Mcfe:
Production:
Lease operating		0.57			0.95			(0.38	)
Workover and other		0.07			0.10			(0.03	)
Taxes other than income		0.52			0.61			(0.09	)
Gathering, transportation and other		0.26			0.17			0.09
General and administrative:
General and administrative		0.45			0.57			(0.12	)
Stock-based compensation		0.11			0.08			0.03
Depletion		3.31			3.07			0.24

(1)

Amounts exclude the impact of cash paid on, or received from, settled contracts.

For the six months ended June 30, 2007, oil and natural gas sales increased $253.3 million, from the same period in 2006, to $442.7 million. The increase was primarily due to the increase in production of 34,497 Mmcfe primarily related to our merger with KCS. The remaining increase in volumes was due to our successful drilling program. Increased production led to a $272.0 million increase in oil and gas revenues for the six months ended June 30, 2007. This was partially offset by a $0.32 per Mcfe decrease in our realized average price which resulted in a reduction of $18.7 million in our oil and gas revenues.

Lease operating expenses increased $10.4 million for the six months ended June 30, 2007. The increase was primarily due to an increase in production volumes as a result of our acquisition activities, as well as our successful drilling activities in 2007. We drilled 181 gross wells during the six months ended June 30, 2007 compared to 130 gross wells in 2006. On a per unit basis, lease operating expenses decreased from $0.95 per Mcfe in 2006 to $0.57 per Mcfe in 2007. The decrease on a per unit basis is primarily due to our continued cost control efforts. Additionally, we continue to identify divestment prospects which tend to be outlying, higher operating cost properties as evident by the transactions that closed during the fourth quarter of 2006. Also contributing to the decrease on a per unit basis was our acquisition of lower cost properties in conjunction with our merger with KCS and properties acquired in the North Louisiana Acquisitions.

Taxes other than income increased $15.7 million for the six months ended June 30, 2007 as compared to the same period in 2006. The largest components of taxes other than income are production and severance taxes which are generally assessed as a percentage of gross oil and natural gas sales. As a percentage of oil and gas sales, taxes other than income decreased 1% to 7% in 2007 from 8% in 2006.

Gathering, transportation and other expense increased $10.9 million, or $0.09 per Mcfe, for the six months ended June 30, 2007 as compared to the same period in 2006. This increase was due to our recent acquisition activities including the completion of our merger with KCS as well as the North Louisiana Acquisitions.

General and administrative expense for the six months ended June 30, 2007 increased $12.5 million to $26.3 million compared to $13.8 million in the same period in 2006. This increase was due to our continued growth over the past two years. In 2006, we completed the North Louisiana Acquisitions as well as our merger with KCS which increased compensation and other costs associated with increased staffing levels to meet the demands of our expanding operations. General and administrative expense has decreased on a per Mcfe basis from $0.57 per Mcfe in 2006 to $0.45 per Mcfe in 2007 as production increases have exceeded our administrative expense increases.

Stock-based compensation increased $4.4 million for the six months ended June 30, 2007 as compared to the same period in the prior year. This increase was primarily related to additional stock options and restricted stock grants assumed as part of our merger with KCS in July 2006, as well as stock appreciation rights and restricted stock grants to employees during 2007.

Depletion expense increased $120.0 million for the six months ended June 30, 2007 from the same period in 2006 to $193.7 million. Depletion for oil and natural gas properties is calculated using the unit of production method, which essentially depletes the capitalized costs associated with the 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. On a per unit basis, depletion expense increased $0.24 per Mcfe to $3.31 per Mcfe from $3.07 per Mcfe. This increase was due to our merger with KCS in July 2006 and the North Louisiana Acquisitions in January 2006 which substantially increased our future development costs.

We enter into derivative commodity instruments to hedge our exposure to price fluctuations on our anticipated oil and natural gas production. 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 valuation of these derivative contracts in the consolidated statement of operations. The Company recorded a net derivative loss of $27.3 million ($45.0 million unrealized loss net of a $17.7 million gain for cash received on settled contracts) for the six months ended June 30, 2007 compared to a net derivative gain of $26.4 million in the prior year. The net derivative loss for six months ended June 30, 2007 was primarily due to the change in the fair value of derivative instruments from December 31, 2006 as our weighted average forward strip price for natural gas increased $0.51 per Mmbtu from December 31, 2006 to June 30, 2007.

Interest expense and other increased $42.5 million for the six months ended June 30, 2007 compared to the same period in 2006. This increase was due to additional debt we incurred in conjunction with our merger with KCS in July 2006 and, to a lesser extent, the North Louisiana Acquisitions in January 2006. Also contributing to this increase was the increase of $147 million in our senior revolving credit facility during the first half of 2007. This increase was used to fund our acquisition and drilling activities as well as other general corporate purposes.

Income tax expense for the six months ended June 30, 2007 decreased $8.1 million from the prior year. The decrease in income tax expense from prior year was primarily due to our pre-tax income of $41.6 million for the six months ended June 30, 2007 compared to pre-tax income of $61.2 million in 2006. The effective tax rates for the six months ended June 30, 2007 and 2006 were 37.0% and 38.3%, respectively. The decrease in our effective tax rate was primarily due to changes in state apportionment percentages due to the merger of KCS properties with historical Petrohawk properties. The 2006 rate was affected by the recognition of a change in the Texas state franchise tax rate due to a change in the tax law. In May 2006, the State of Texas enacted substantial changes to its tax structure beginning in 2007 by imposing a new tax based upon modified gross revenue referred to as the “Margin Tax.” We determined the “Margin Tax” to be an income tax as defined under Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes.

Recently Issued Accounting Pronouncements

We discuss recently adopted and issued accounting standards in Item 1. Condensed Consolidated Financial Statements—Note 1, “Financial Statement Presentation.”

Item 3.

Quantitative and Qualitative Disclosures about Market Risk

Derivative Instruments and Hedging Activity

We are exposed to various risks including energy commodity price risk. We expect energy prices to remain volatile and unpredictable. If energy prices were to decline significantly, revenues and cash flow would significantly decline, and our ability to borrow to finance our operations could be adversely impacted. We have designed our risk management policy to reduce the risk of price volatility for our production in the natural gas and crude oil markets. Our risk management policy provides for the use of derivative instruments to manage these risks. The types of derivative instruments that we utilize include futures, swaps and options. The volume of derivative instruments that we may utilize is governed by the risk management policy and can vary from year to year, but under most circumstances will apply to only a portion of our current and anticipated production and provide only partial price protection against declines in oil and natural gas prices. We are exposed to market risk on our open contracts, to the extent of changes in market prices of oil and natural gas. However, the market risk exposure on these hedged contracts is generally offset by the gain or loss recognized upon the ultimate sale of the commodity that is hedged. Further, if our counterparties defaulted, this protection might be limited as we might not receive the benefits of the hedges. Please refer to Item 1. Condensed Consolidated Financial Statements—Note 7, “Derivative Activities” for additional information.

Interest Sensitivity

We are also 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, 2007, total debt excluding related discounts and premiums was $1.5 billion, of which approximately 70.4%, or $1.1 billion, bears interest at a weighted average fixed interest rate of 8.6% per year. The remaining 29.6% of our total debt balance at June 30, 2007, or $442.0 million, bears interest at floating or market interest rates that at our option are tied to the prime interest rate or LIBOR. Fluctuations in market interest rates will cause our annual interest costs to fluctuate. At June 30, 2007, the interest rate on our variable rate debt was 7.0% per year. If the balance of our bank debt at June 30, 2007 were to remain constant, a 10% change in market interest rates would impact our cash flow by approximately $0.8 million per quarter.

Item 4.

Controls and Procedures

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, 2007 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.

PART II. OTHER INFORMATION

Item 1.

Legal Proceedings

A description of our legal proceedings is included in Item 1. Condensed Consolidated Financial Statements—Note 6, “Commitments and Contingencies,” and is incorporated herein by reference.

Item 1A.

Risk Factors

There have been no changes to the Company’s identified risk factors from those described in the 2006 Form 10-K, as amended.

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds

None.

Item 3.

Defaults Upon Senior Securities

None.

Item 4.

Submission of Matters to a Vote of Security Holders

None.

Item 5.

Other Information

None.

Item 6.

Exhibits

The following documents are included as exhibits to this 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.


Exhibit No		Description
2.1		Stock Purchase Agreement among Winwell Resources, Inc. and all of its Shareholders, as Sellers, and Petrohawk Energy Corporation, as Buyer, dated as of December 14, 2005 (Incorporated by reference to Exhibit 2.1 of our Current Report on Form 8-K filed December 20, 2005).

2.2		Asset Purchase Agreement among Redley Company, Burris Run Company and Red Clay Minerals, collectively as Seller, and Petrohawk Energy Corporation, as Buyer, dated as of December 14, 2005 (Incorporated by reference to Exhibit 2.2 of our Current Report on Form 8-K filed December 20, 2005).

2.3		First Amendment to Asset Purchase Agreement among Redley Company, Burris Run Company and Red Clay Minerals, collectively as Seller, and Petrohawk Energy Corporation, as Buyer, effective as of December 14, 2005 (Incorporated by reference to Exhibit 2.7 to our Annual Report on Form 10-K filed March 14, 2006).

2.4		Amended and Restated Agreement and Plan of Merger executed as of May 16, 2006, and effective as of April 20, 2006 by and among KCS Energy, Inc., Petrohawk Energy Corporation and Hawk Nest Corporation (Incorporated by reference to Exhibit 2.1 of our Current Report on Form 8-K filed May 18, 2006).

3.1		Certificate of Incorporation for Petrohawk Energy Corporation (Incorporated by reference to Exhibit 3.1 to our Form S-8 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).

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).

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 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 July 17, 2006).

4.8		Indenture dated July 12, 2006 among Petrohawk Energy Corporation, U.S. Bank National Association, as trustee, and the subsidiary guarantors named therein, relating to Petrohawk Energy Corporation’s 9¹/8% senior notes due 2013 (Incorporated by reference to Exhibit 4.6 to our Current Report on Form 8-K filed July 17, 2006).

4.9		First Supplemental Indenture dated July 12, 2006 among Petrohawk Energy Corporation, U.S. Bank National Association, as trustee, and the subsidiary guarantors named therein (Incorporated by reference to Exhibit 4.7 to our Current Report on Form 8-K filed July 17, 2006).

10.1*		Second Amendment to Second Amended and Restated Senior Revolving Credit Agreement dated as of July 12, 2006 among the Company, each of the lenders from time to time party thereto, BNP Paribas, as administrative agent for the lenders, Bank of America, N.A. and BMO Capital Markets Financing, Inc., as co-syndication agents for the lenders, and JPMorgan Chase Bank, N.A, Wells Fargo Bank, N.A and Fortis Capital Corp., as co-documentation agents for the lenders.

10.2*		Third Amendment to Second Amended and Restated Senior Revolving Credit Agreement dated as of July 12, 2006 among the Company, each of the lenders from time to time party thereto, BNP Paribas, as administrative agent for the lenders, Bank of America, N.A. and BMO Capital Markets Financing, Inc., as co-syndication agents for the lenders, and JPMorgan Chase Bank, N.A, Wells Fargo Bank, N.A and Fortis Capital Corp., as co-documentation agents for the lenders.

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 Sarbanes-Oxley Act of 2002

32.1*		Certificate of Chief Executive Officer and Chief Financial Officer under Section 906 of the Sarbanes-Oxley Act of 2002

*	Attached hereto.

The registrant has not filed with this report copies of the instruments defining rights of all holders of long-term debt of the registrant and its consolidated subsidiaries based upon the exception set forth in Item 601 (b)(4)(iii)(A) of Regulation S-K. Copies of such instruments will be furnished to the Securities and Exchange Commission upon request.

SIGNATURES

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


	PETROHAWK ENERGY CORPORATION

Date: August 7, 2007	By:	/s/ Floyd C. Wilson
		Floyd C. Wilson
		Chairman of the Board, President and Chief Executive Officer

	By:	/s/ Shane M. Bayless
		Shane M. Bayless
		Executive Vice President, Chief Financial Officer and Treasurer

	By:	/s/ Mark J. Mize
		Mark J. Mize
		Vice President, Chief Accounting Officer and Controller

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