Edgar Filing: PETROHAWK ENERGY CORP

Form 10-Q for quarterly period ended June 30, 2008

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, 2008

Commission file number 001-33334

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:


Title of each class				Name of each exchange on which registered
Common Stock, par value $.001 per share				New York Stock Exchange

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

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

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


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

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 1, 2008 the Registrant had 222,231,763 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, 2008 and 2007	4

	Consolidated balance sheets as of June 30, 2008 and December 31, 2007	5

	Consolidated statements of cash flows for the six months ended June 30, 2008 and 2007	6

	Notes to condensed consolidated financial statements	7

ITEM 2.	Management’s discussion and analysis of financial condition and results of operations	22

ITEM 3.	Quantitative and qualitative disclosures about market risk	31

ITEM 4.	Controls and procedures	32

PART II. OTHER INFORMATION

ITEM 1.	Legal proceedings	32

ITEM 1A.	Risk factors	32

ITEM 2.	Unregistered sales of equity securities and use of proceeds	34

ITEM 3.	Defaults upon senior securities	34

ITEM 4.	Submission of matters to a vote of security holders	34

ITEM 5.	Other information	35

ITEM 6.	Exhibits	35

Special note regarding forward-looking statements

This report on Form 10-Q contains forward-looking statements within the meaning of the federal securities laws. All statements, other than statements of historical facts, are forward-looking statements.

Forward-looking statements are identified by use of terms and phrases such as “may,” “expect,” “estimate,” “project,” “plan,” “believe,” “intend,” “achievable,” “anticipate,” “will,” “continue,” “potential,” “should,” “could” and similar words and phrases. Although we believe that the expectations reflected in these forward-looking statements are reasonable, they do involve certain assumptions, risks and uncertainties. Our actual results could differ materially from those anticipated in these 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 our Form 10-K for the year ended December 31, 2007, 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:

•

our ability to successfully develop our large inventory of undeveloped acreage primarily held in resource-style areas in Arkansas and Louisiana including our higher risk plays such as Haynesville Shale;

•

the volatility in commodity prices for oil and natural gas;

•

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

•

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

•

our ability to generate sufficient cash flow from operations, borrowings or other sources to enable us to fully develop our undeveloped acreage positions;

•

the ability to replace oil and natural gas reserves;

•

environmental risks;

•

drilling and operating risks;

•

exploration and development risks;

•

competition, including competition for acreage in resource-style areas;

•

management’s ability to execute our plans to meet our goals;

•

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

•

our ability to obtain goods and services, such as drilling rigs and tubulars, and access to adequate gathering systems and pipeline take-away capacity, to execute our drilling program;

•

general economic conditions, whether internationally, nationally or in the regional and local market areas in which we do business, may be less favorable than expected, including the possibility that the United States may be entering into an economic slow-down which could affect the demand for natural gas, oil and natural gas liquids;

•

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 may negatively impact our business, operations or pricing.

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

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,
	2008			2007			2008			2007
Operating revenues:
Oil and gas	$	304,633		$	233,482		$	519,571		$	442,725
Operating expenses:
Production:
Lease operating		12,903			17,416			25,297			33,292
Workover and other		1,249			1,845			1,786			4,022
Taxes other than income		14,036			16,628			25,000			30,278
Gathering, transportation and other		10,944			7,599			20,467			15,023
General and administrative		17,214			16,980			33,368			32,581
Depletion, depreciation and amortization		86,694			100,210			169,821			196,048

Total operating expenses		143,040			160,678			275,739			311,244

Income from operations		161,593			72,804			243,832			131,481
Other expenses:
Net (loss)gain on derivative contracts		(277,605	)		31,591			(420,346	)		(27,342	)
Interest expense and other		(35,154	)		(31,789	)		(62,691	)		(62,539	)

Total other expenses		(312,759	)		(198	)		(483,037	)		(89,881	)

(Loss) income before income taxes		(151,166	)		72,606			(239,205	)		41,600
Income tax benefit (provision)		58,400			(26,975	)		90,827			(15,384	)

Net (loss) income available to common stockholders	$	(92,766	)	$	45,631		$	(148,378	)	$	26,216

Net (loss) income per share of common stock:
Basic	$	(0.45	)	$	0.27		$	(0.76	)	$	0.16

Diluted	$	(0.45	)	$	0.27		$	(0.76	)	$	0.15

Weighted average shares outstanding:
Basic		206,490			167,783			195,060			167,546

Diluted		206,490			172,113			195,060			171,490

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, 2008			December 31, 2007
Current assets:
Cash	$	1,075		$	1,812
Marketable securities		489,711			—
Accounts receivable		212,328			148,138
Current portion of deferred income taxes		115,490			5,855
Receivables from derivative contracts		3,299			12,369
Prepaid and other		23,126			21,019

Total current assets		845,029			189,193

Oil and gas properties (full cost method):
Evaluated		3,977,720			3,247,304
Unevaluated		1,363,702			677,565

Gross oil and gas properties		5,341,422			3,924,869
Less - accumulated depletion		(936,867	)		(769,197	)

Net oil and gas properties		4,404,555			3,155,672

Other operating property and equipment:
Gross other operating property and equipment		50,317			18,940
Less - accumulated depreciation		(8,396	)		(6,838	)

Net other operating property and equipment		41,921			12,102

Other noncurrent assets:
Goodwill		933,916			933,945
Debt issuance costs, net of amortization		28,139			12,052
Receivables from derivative contracts		5,059			—
Restricted cash (Note 2)		—			269,837
Note receivable (Note 2)		—			96,098
Other		1,092			3,540

Total assets	$	6,259,711		$	4,672,439

Current liabilities:
Accounts payable and accrued liabilities	$	430,797		$	331,471
Liabilities from derivative contracts		277,044			28,198
Current portion of long-term debt		5,539			828

Total current liabilities		713,380			360,497

Long-term debt		1,831,337			1,595,127
Liabilities from derivative contracts		109,774			6,915
Asset retirement obligations		26,640			23,800
Deferred income taxes		676,097			674,968
Other noncurrent liabilities		2,191			2,235
Commitments and contingencies (Note 6)
Stockholders’ equity:
Common stock: 300,000,000 shares of $.001 par value authorized; 222,183,748 and 171,220,817 shares issued and outstanding at June 30, 2008 and December 31, 2007, respectively		222			171
Additional paid-in capital		2,911,238			1,871,516
(Accumulated deficit) retained earnings		(11,168	)		137,210

Total stockholders’ equity		2,900,292			2,008,897

Total liabilities and stockholders’ equity	$	6,259,711		$	4,672,439

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,
	2008			2007
Cash flows from operating activities:
Net (loss) income	$	(148,378	)	$	26,216
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depletion, depreciation and amortization		169,821			196,048
Income tax (benefit) provision		(90,827	)		15,384
Stock-based compensation		5,679			6,285
Net unrealized loss on derivative contracts		366,580			45,038
Net realized gain on derivative contracts acquired		—			(2,429	)
Other		81			2,738
Change in assets and liabilities, net of acquisitions:
Accounts receivable		(79,109	)		2,670
Prepaid expenses and other		(2,107	)		196
Accounts payable and accrued liabilities		64,445			10,098
Other		2,404			225

Net cash provided by operating activities		288,589			302,469

Cash flows from investing activities:
Oil and gas capital expenditures		(1,394,107	)		(455,893	)
Proceeds received from sale of oil and gas properties		110,900			8,855
Marketable securities purchased		(1,116,098	)		—
Marketable securities redeemed		626,387			—
Decrease in restricted cash		269,837			—
Other operating property and equipment expenditures		(31,041	)		(1,985	)

Net cash used in investing activities		(1,534,122	)		(449,023	)

Cash flows from financing activities:
Proceeds from exercise of options		10,260			1,966
Proceeds from issuance of common stock		1,069,213			—
Offering costs		(44,717	)		—
Proceeds from borrowings		1,596,000			487,000
Repayment of borrowings		(1,367,401	)		(342,838	)
Debt issue costs		(18,559	)		—
Net realized gain on derivative contracts acquired		—			2,429
Other		—			(1,499	)

Net cash provided by financing activities		1,244,796			147,058

Net (decrease) increase in cash		(737	)		504
Cash at beginning of period		1,812			5,593

Cash at end of period	$	1,075		$	6,097

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 2007 Annual Report on Form 10-K with the exception of the adoption of Financial Accounting Standards Board (FASB) Statement of Financial Accounting Standards (SFAS) No. 157, Fair Value Measurements as described in “Recently Issued Accounting Pronouncements” below. Please refer to the footnotes in the 2007 Form 10-K, 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. Certain prior year amounts have been reclassified to conform to the current year presentation.

Risk Management Activities

The Company follows SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities (SFAS 133), as amended by SFAS No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities, an amendment of FASB Statement No. 133, SFAS No. 149, Amendment of Statement No. 133 on Derivative Instruments and Hedging Activities and SFAS No. 155, Accounting for Certain Hybrid Financial Instruments. From time to time, the Company may hedge a portion of its forecasted oil and natural gas production. Derivative contracts entered into by the Company have consisted of transactions in which the Company hedges the variability of cash flow related to a forecasted transaction. The Company has elected to not designate any of its positions for hedge accounting. Accordingly, the Company records the net change in the mark-to-market valuation of these positions, as well as payments and receipts on settled contracts, in net gain (loss) on derivative contracts on the consolidated statements of operations.

During the first quarter of 2008, the Company made the decision to mitigate a portion of its interest rate risk with interest rate swaps, which reduce the exposure to market rate fluctuations by converting variable interest rates to fixed interest rates. These interest rate swaps convert a portion of the Company’s Credit Agreement (as defined in Note 4, “Long-term Debt”) to a fixed rate obligation, thereby reducing the exposure to market rate fluctuations. The Company has elected to not designate any of its positions for hedge accounting. Accordingly, the Company records the net change in the mark-to-market valuation of these positions, as well as all payments and receipts on settled contracts, in net gain (loss) on derivatives contracts on the consolidated statements of operations. During the second quarter of 2008, the Company repaid all outstanding borrowings under its Credit Agreement. As a result, the Company made the decision to sell all of its outstanding interest rate swap positions which resulted in a gain of $1.5 million during the second quarter of 2008 which is included in net gain (loss) on derivative contracts on the consolidated statements of operations.

Marketable Securities

During the second quarter of 2008, the Company made the decision to invest a portion of its cash in money market mutual funds which are highly liquid marketable securities. The Company accounts for marketable securities in accordance with SFAS No. 115, Accounting for Certain Investments in Debt and Equity Securities and classifies marketable securities as trading, available-for-sale, or held-to-maturity. The appropriate classification of its marketable securities is determined at the time of purchase and reevaluated at each balance sheet date.

At June 30, 2008, the Company held approximately $490 million of marketable securities which have been classified and accounted for as trading securities. Trading securities are recorded at fair value with realized gains and losses reported in interest expense and other in the consolidated statements of operations.

Recently Issued Accounting Pronouncements

In May 2008, the FASB issued SFAS No. 162, The Hierarchy of Generally Accepted Accounting Principles, (SFAS 162), which identifies a consistent framework for selecting accounting principles to be used in preparing financial statements for nongovernmental entities that are presented in conformity with United States generally accepted accounting principles (GAAP). The current GAAP hierarchy was criticized due to its complexity, ranking position of FASB Statements of Financial Accounting Concepts and the fact that it is directed at auditors rather than entities. SFAS 162 will be effective 60 days following the SEC’s approval of the Public Company Accounting Oversight Board amendments to AU Section 411, The Meaning of Present Fairly in Conformity with Generally Accepted Accounting Principles. The FASB does not expect that SFAS 162 will have a change in current practice, and the Company does not believe that SFAS 162 will have an impact on operating results, financial position or cash flows.

In March 2008, the FASB issued Statement No. 161, Disclosures about Derivative Instruments and Hedging Activities—an amendment of FASB Statement No. 133 (SFAS 161). SFAS 161 requires entities that utilize derivative instruments to provide qualitative disclosures about their objectives and strategies for using such instruments, as well as any details of credit-risk-related contingent features contained within derivatives. SFAS 161 also requires entities to disclose additional information about the amounts and location of derivatives located within the financial statements, how the provisions of SFAS 133 have been applied, and the impact that hedges have on an entity’s operating results, financial position or cash flows. SFAS 161 is effective for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged. The Company is currently assessing the impact, if any, that the adoption of this pronouncement will have on the Company’s disclosures.

In December 2007, the FASB issued SFAS No. 141, Business Combinations (SFAS 141R), and SFAS No. 160, Accounting and Reporting of Noncontrolling Interest in Consolidated Financial Statements, an amendment of ARB No. 51 (SFAS 160). SFAS 141R and SFAS 160 will significantly change the accounting for and reporting of business combination transactions and noncontrolling (minority) interests in consolidated financial statements. SFAS 141R retains the fundamental requirements in Statement 141, Business Combinations, while providing additional definitions, such as the definition of the acquirer in a purchase and improvements in the application of how the acquisition method is applied. SFAS 160 will change the accounting and reporting for minority interests, which will be recharacterized as noncontrolling interests, and classified as a component of equity. These Statements become simultaneously effective January 1, 2009. Early adoption is not permitted. 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 April 2007, the FASB issued FSP No. FIN 39-1, Amendment of FASB Interpretation No. 39, (FIN 39-1) to amend FIN 39, Offsetting of Amounts Related to Certain Contracts (FIN 39). The terms “conditional contracts” and “exchange contracts” used in FIN 39 have been replaced with the more general term “derivative contracts.” In addition, FIN 39-1 permits the offsetting of recognized fair values for the right to reclaim cash collateral or the obligation to return cash collateral against fair values of derivatives under certain circumstances, such as under master netting arrangements. Additional disclosure is also required regarding a Company’s accounting policy with respect to offsetting fair value amounts. The Company adopted FIN 39-1 on January 1, 2008 and no change in accounting principle was necessary and there was no impact on the Company’s operating results, financial position or cash flows.

In February 2007, the FASB issued 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. Following the election of the Fair Value Option for certain financial assets and liabilities, the Company would report unrealized gains and losses

due to changes in fair value in earnings at each subsequent reporting date. The Company adopted SFAS 159 effective January 1, 2008 which did not have a material impact on the Company’s operating results, financial position or cash flows as the Company did not elect the Fair Value Option for any of its financial assets or liabilities.

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 measurements. The Company adopted the provisions of SFAS 157 on January 1, 2008. See “Fair Value Measurements” below for more details.

Fair Value Measurements

In September 2006, the FASB issued SFAS 157 which defines fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements. The provisions of SFAS 157 are effective January 1, 2008. The FASB has also issued Staff Position FAS 157-2 (FSP No. 157-2), which delays the effective date of SFAS 157 for nonfinancial assets and liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually), until fiscal years beginning after November 15, 2008. Effective January 1, 2008, the Company adopted SFAS 157 as discussed above and has elected to defer the application thereof to nonfinancial assets and liabilities in accordance with FSP No. 157-2. Non-recurring nonfinancial assets and nonfinancial liabilities for which the Company has not applied the provisions of SFAS 157 include those measured at fair value in goodwill impairment testing, asset retirement obligations initially measured at fair value, and those initially measured at fair value in a business combination.

The Company utilizes derivative contracts to economically hedge against the variability in cash flows associated with the forecasted sale of its anticipated future oil and natural gas production. The Company generally economically hedges a substantial, but varying, portion of anticipated oil and natural gas production for the next 12-36 months. Derivatives are carried at fair value on the consolidated balance sheets, with the changes in the fair value included in the consolidated statement of operations for the period in which the change occurs.

Periodically, the Company utilizes marketable securities to invest a portion of its cash on hand. These securities are carried at fair value on the consolidated balance sheets, with the changes in the fair value included in the consolidated statements of operations for the period in which the change occurs.

As defined in SFAS 157, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. The Company classifies fair value balances based on the observability of those inputs. SFAS 157 establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1 measurement) and the lowest priority to unobservable inputs (level 3 measurement).

The three levels of the fair value hierarchy defined by SFAS 157 are as follows:

Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 1 primarily consists of financial instruments such as exchange-traded derivatives, marketable securities and listed equities.

Level 2 – Pricing inputs are other than quoted prices in active markets included in level 1, which are either directly or indirectly observable as of the reported date. Level 2 includes those financial instruments that are

valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category generally include non-exchange-traded derivatives such as commodity swaps, interest rate swaps, options and collars.

Level 3 – Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value.

The following table sets forth by level within the fair value hierarchy the Company’s financial assets and liabilities that were accounted for at fair value as of June 30, 2008. As required by SFAS 157, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.


Recurring Fair Value Measures	June 30, 2008
Recurring Fair Value Measures	Level 1		Level 2		Level 3		Total
	(Dollars in thousands)
Assets
Marketable securities	$	489,711	$	—	$	—	$	489,711
Receivables from derivative contracts		—		8,358		—		8,358

	$	489,711	$	8,358	$	—	$	498,069

Liabilities
Liabilities from derivative contracts	$	—	$	386,818	$	—	$	386,818

Derivatives listed above include commodity swaps, options and collars that are carried at fair value. The fair value amounts in current period earnings associated with the Company’s derivatives resulted from Level 2 fair value methodologies; that is, the Company is able to value the assets and liabilities based on observable market data for similar instruments. This observable data includes the forward curve for commodity prices based on quoted markets prices and prospective volatility factors related to changes in the forward curves.

Marketable securities listed above are carried at fair value. The fair value amounts in current period earnings associated with the Company’s marketable securities resulted from Level 1 fair value methodologies; that is, the Company is able to value the assets based on quoted fair values for identical instruments.

2. ACQUISITIONS AND DIVESTITURES

Acquisitions

Fayetteville Shale

On January 7, 2008, the Company entered into an agreement to purchase additional properties located in the Fayetteville Shale for $231.3 million after customary closing adjustments. The transaction closed on February 8, 2008. The acquired properties include interests primarily in Van Buren and Cleburne Counties, Arkansas. These properties are substantially undeveloped. During the second half of 2007, the Company completed three separate acquisitions for total cash consideration of approximately $409 million.

Elm Grove Field

On January 22, 2008, the Company completed an acquisition of interests in the Elm Grove Field, located primarily in Bossier and Caddo Parishes of North Louisiana, for approximately $169 million.

One TEC, LLC

On August 3, 2007 the Company completed the acquisition of all of the membership interests of One TEC, LLC (One TEC) for approximately $42.0 million. The One TEC acquisition was accounted for using the purchase method of accounting under the accounting standards established in SFAS No. 141, Business Combinations and SFAS No. 142, Goodwill and Other Intangible Assets. As a result, the assets and liabilities of One TEC were first reported in the Company’s consolidated balance sheet as of September 30, 2007. The Company reflected the results of operations of One TEC beginning August 3, 2007. The Company recorded the estimated fair values of the assets acquired and liabilities assumed at August 3, 2007, which primarily consisted of oil and natural gas properties of $35.0 million.

Divestitures

Gulf Coast Properties

In June 2007, the Company announced a strategic repositioning involving plans to sell its Gulf Coast properties and concentrate its efforts on developing and expanding the Company’s resource-style assets, including tight-gas properties in North Louisiana and the Fayetteville Shale in central Arkansas. On November 30, 2007, the Company completed the sale of its Gulf Coast properties for $825 million, consisting of $700 million in cash and a $125 million note that the purchaser could redeem at any time prior to one year from November 30, 2007 for $100 million plus accrued and unpaid interest. If the redemption occurred prior to April 29, 2008, accrued interest would be waived. The economic effective date for the sale was July 1, 2007. Proceeds from the sale were recorded as a decrease to the Company’s full cost pool. The note was recorded upon closing at $100 million less a discount of $4.8 million, or approximately $95.2 million. On April 28, 2008, the purchaser redeemed the note for $100 million.

In conjunction with the closing of this sale, the Company deposited $650 million with a qualified intermediary to facilitate potential like-kind exchange transactions, all of which was utilized for property acquisitions completed during the fourth quarter of 2007 and first quarter of 2008.

In connection with the sale of the Company’s Gulf Coast properties, the employment of certain employees was terminated, giving rise to termination benefits resulting in additional general and administrative expenses of $9.5 million recorded by the Company on November 30, 2007. In addition, outstanding stock appreciation rights, stock options and restricted share awards to employees whose employment was terminated in connection with the sale were modified to extend the exercise period from 90 days to November 30, 2008, as well as to accelerate the vesting of those awards. As a result of these two modifications, the Company recognized an additional $2.4 million of stock-based compensation expense on November 30, 2007.

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 capitalized costs of evaluated 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 are charged to expense. Full cost companies use the prices in effect at the end of each accounting quarter to calculate the ceiling test value of their reserves. The SEC permits, and the Company has elected, the use of subsequent prices to the extent prices recover subsequent to quarter end and before the filing of the report.

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, 2008 and December 31, 2007 consisted of the following:


	June 30, 2008		December 31, 2007
	(In thousands)
Senior revolving credit facility	$	—	$	570,000
7⁷/8% $800 million senior notes		800,000		—
9¹/8% $775 million senior notes⁽¹⁾		763,343		762,934
7¹/8% $275 million senior notes⁽²⁾		262,988		261,939
9⁷/8% senior notes		254		254
Deferred premiums on derivatives⁽³⁾		4,752		—

	$	1,831,337	$	1,595,127

(1)

This amount is comprised of the $650.0 million and $125.0 million private placements consummated in July 2006. These amounts include a $6.4 million and $6.9 million discount at June 30, 2008 and December 31, 2007, respectively, recorded by the Company in conjunction with the issuance of the $650.0 million notes. Additionally, these amounts include a $1.0 million premium at June 30, 2008 and December 31, 2007, recorded by the Company in conjunction with the issuance of the $125.0 million notes. See “9¹/8% Senior Notes” below for more details.

(2)	Amount includes a $9.4 million and $10.4 million discount at June 30, 2008 and December 31, 2007, respectively, recorded by the Company in conjunction with the assumption of the notes. See “7¹/8% Senior Notes” below for more details.

(3)	Amount excludes $5.5 million and $0.8 million of deferred premiums on derivatives which have been classified as current at June 30, 2008 and December 31, 2007, respectively.

Senior Revolving Credit Facility

Effective February 5, 2008, the Company entered into the Fifth Amendment (the Fifth Amendment) to the Second Amended and Restated Senior Revolving Credit Agreement dated as of July 12, 2006 (the Credit Agreement) among the Company, each of the lenders from time to time party thereto (the Lenders), BNP Paribas, as administrative agent for the Lenders, Bank of America, N.A. and 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. Pursuant to the Fifth Amendment, the Company’s borrowing base under the Credit Agreement was increased from $675 million to $1 billion, inclusive of a $100 million component set to expire effective February 5, 2009.

Effective May 5, 2008, the Company entered into the Sixth Amendment (the Sixth Amendment) to the Credit Agreement. The Sixth Amendment modified the covenant limiting the Company’s ability to enter into

commodity hedge agreements to provide that through 2010 the notional volumes for commodity hedge agreements could not exceed, at the time a hedge agreement is executed or any time thereafter, 100% of the lesser of current production during each month the hedge is in effect, or total internally forecasted production for each month for the next 48 months. In addition, the Sixth Amendment provides hedges cannot exceed 75% and 50% of such amounts in 2011 and 2012, respectively. The Sixth Amendment also included a waiver as of March 31, 2008 for existing commodity hedge agreements involving in excess of 85% of projected production from proved, developed producing oil and gas properties, provided that the Company would be in compliance with the commodity hedge agreement covenant as amended, had that been in effect. The Sixth Amendment also modified the covenant limiting the Company’s ability to incur certain debt to permit the Company to incur certain additional long-term debt in the form of senior notes subject to a simultaneous reduction in the Company’s borrowing base then in effect by an amount equal to the product of $0.25 multiplied by the stated principal amount (without regard to any initial issue discount) of any notes that the Company may issue.

On May 13, 2008, the Company issued $500 million of 7⁷/8% senior notes due 2015. The Company issued an additional $300 million of 7⁷/ 8% senior notes due 2015 on June 19, 2008. As a result, the Company’s borrowing base was decreased to $800 million. See “7⁷/8% Senior Notes” below for more details on these offerings.

Amounts outstanding under the Credit Agreement bear interest at specified margins of 1.00% to 2.00% over LIBOR for Eurodollar loans and 0.00% to 0.75% over ABR for ABR loans. Borrowings are collateralized by first priority liens on substantially all of the Company’s assets and all of the assets of, and equity interest in, its subsidiaries. The facility matures on July 12, 2010.

The Credit Agreement contains customary financial and other covenants, including a minimum interest coverage ratio of not less than 2.5 to 1.0, a maximum leverage ratio of 4.0 to 1.0, and a current ratio (the ratio of current assets plus the unused commitment under the Credit Agreement to current liabilities) of not less than 1.0 to 1.0. In addition, the Credit Agreement, as amended, contains covenants limiting dividends and other restricted payments, transactions with affiliates, the incurrence of debt, changes of control, asset sales, and liens on properties, including a covenant limiting certain commodities hedging transactions, as described above. At June 30, 2008, the Company was in compliance with all of its debt covenants under the Credit Agreement.

7⁷/8% Senior Notes

On May 13, 2008 and June 19, 2008, the Company issued $500 million principal amount and $300 million principal amount, respectively, of its 7⁷/8% senior notes due 2015 (the 2015 Notes). The 2015 Notes were issued under and are governed by an indenture dated May 13, 2008, between the Company, U.S. Bank Trust National Association, as trustee, and the Company’s subsidiaries named therein as guarantors.

The 2015 Notes bear interest at a rate of 7.875% per annum, payable semi-annually on June 1 and December 1 of each year, commencing December 1, 2008. The 2015 notes will mature on June 1, 2015. The 2015 Notes are senior unsecured obligations of the Company and rank equally with all of its current and future senior indebtedness. The 2015 Notes are jointly and severally guaranteed on a senior unsecured basis by the Company’s subsidiaries. Petrohawk Energy Corporation, the issuer of the Notes, has no material independent assets or operations apart from the assets and operations of its subsidiaries.

On or before June 1, 2011, the Company may redeem up to 35% of the aggregate principal amount of the 2015 Notes with the net cash proceeds of certain equity offerings at a redemption price of 107.875% of the principal amount plus accrued interest and unpaid interest to the redemption date provided that: at least 65% in aggregate principal amount of the 2015 Notes originally issued under the 2015 Indenture remain outstanding immediately after the redemption. In addition, at any time prior to June 1, 2012, the Company may redeem some or all of the 2015 Notes for the principal amount thereof, plus accrued and unpaid interest plus a make whole premium equal to the excess, if any of (a) the present value at such time of (i) the redemption price of such note

at June 1, 2012, (ii) plus required interest payments due on the notes, computed using a discount rate based upon the yield of U.S. Treasury securities with a constant maturity most nearly equal to the period from the redemption date to June 1, 2012 plus 50 basis points, over (b) the principal amount of such note.

On or after June 1, 2012, the Company may redeem some or all of the 2015 Notes at any time or from time to time at the redemption prices (expressed as a percentage of principal amount) set forth in the following table plus accrued and unpaid interest, if any, to the applicable redemption date, if redeemed during the 12-month period beginning June 1 of the years indicated below:


Year		Percentage
2012		103.938
2013		101.969
2014		100.000

The Company may be required to offer to repurchase the 2015 Notes at a purchase price of 101% of the principal amount, plus accrued and unpaid interest, if any, to the redemption date, in the event of a change of control as defined in the 2015 Indenture.

The 2015 Indenture contains covenants that, among other things, restrict or limit the ability of the Company and its subsidiaries to: borrow money; pay dividends on stock; purchase or redeem stock or subordinated indebtedness; make investments; create liens; enter into transactions with affiliates; sell assets; and merge with or into other companies or transfer all or substantially all of the Company’s assets. At June 30, 2008, the Company is in compliance with all of its debt covenants relating to the 2015 Notes.

9¹/8% Senior Notes

In July 2006, the Company issued 9¹/ 8% Senior Notes, also referred to as the 2013 Notes, pursuant to an Indenture dated as of July 12, 2006 (2013 Indenture) and the First Supplemental Indenture to the 2013 Notes among the Company, the Company’s subsidiaries named therein as guarantors, and U.S. Bank National Association, as trustee. The 2013 Notes were issued in two tranches, $650 million on July 12, 2006 at 98.735% of the face amount and $125 million on July 27, 2006 at 101.25% of the face amount of $775 million.

In conjunction with the July 12, 2006 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 $6.4 million at June 30, 2008. In conjunction with the July 27, 2006 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 $1.0 million at June 30, 2008.

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 and 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. The 2013 Notes are jointly and severally guaranteed on a senior unsecured basis by the Company’s subsidiaries. Petrohawk Energy Corporation, the issuer of the Notes, has no material independent assets or operations apart from the assets and operations of its subsidiaries.

The 2013 Indenture contains covenants that, among other things, restrict or limit the ability of the Company and its subsidiaries to: borrow money; pay dividends on stock; purchase or redeem stock or subordinated indebtedness; make investments; create liens; enter into transactions with affiliates; sell assets; and merge with or into other companies or transfer all or substantially all of the Company’s assets. At June 30, 2008, the Company is in compliance with all of its debt covenants relating to the 2013 Notes.

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 7¹/8% Senior Notes, also referred to as the 2012 Notes), and subsidiaries of the Company guaranteed (pursuant to the Third Supplemental Indenture relating to such notes), all the obligations (approximately $275 million) of KCS under the 2012 Notes and the Indenture dated April 1, 2004 (the 2012 Indenture) among KCS, U.S. Bank National Association, as trustee, and the subsidiary guarantors named therein, which governs the terms of the 2012 Notes.

In conjunction with the assumption of the 7¹/8% Senior Notes from KCS, the Company recorded a discount of $13.6 million to be amortized over the remaining life of the notes utilizing the effective interest rate method. The remaining unamortized discount is $9.4 million at June 30, 2008.

The 2012 Notes bear interest at the rate of 7.125% per annum, payable semi-annually on April 1 and October 1 of each year and mature on April 1, 2012. The 2012 Notes are senior unsecured obligations of the Company and rank equally with all of its current and future senior indebtedness. The 2012 Notes are jointly and severally guaranteed on a senior unsecured basis by the Company’s subsidiaries. Petrohawk Energy Corporation, the issuer of the Notes, has no material independent assets or operations apart from the assets and operations of its subsidiaries.

The 2012 Indenture contains covenants that, among other things, restrict or limit the ability of the Company and its subsidiaries to: borrow money; pay dividends on stock; purchase or redeem stock or subordinated indebtedness; make investments; create liens; enter into transactions with affiliates; sell assets; and merge with or into other companies or transfer all or substantially all of the Company’s assets. At June 30, 2008, the Company is in compliance with all of its debt covenants relating to the 2012 Notes.

9⁷/8% Senior Notes

On April 8, 2004, Mission Resources Corporation (Mission) 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 repurchased substantially all of the 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 repurchased and remained outstanding as of June 30, 2008. In connection with the repurchase, the indenture governing the notes was amended to largely eliminate the covenants associated with the 2011 Notes.

Debt Issuance Costs

The Company capitalizes certain direct costs associated with the issuance of long-term debt. The Company capitalized $18.6 million of debt issue costs primarily in connection with the Company’s issuance of 2015 Notes in May and June 2008. At June 30, 2008, the Company had approximately $28.1 million of debt issuance costs remaining that are 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 costs 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, 2008:


Liability for asset retirement obligation as of December 31, 2007	$	23,800
Liabilities settled and divested		(254	)
Additions		1,356
Acquisitions ⁽¹⁾		1,145
Accretion expense		593

Liability for asset retirement obligation as of June 30, 2008	$	26,640

(1)	Refer to Note 2, “Acquisitions and Divestitures” for more details on the Company’s acquisition activities.

6. COMMITMENTS AND 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 its Form 10-K for the year ended December 31, 2007, the Company disclosed that it had 12 drilling rigs under contract for a total commitment over three years of $69.3 million. As of June 30, 2008, the Company has 28 drilling rigs under contract for a total commitment over three years of $276.7 million.

The Company has various other contractual commitments pertaining to exploration, development and production activities. The Company has work related commitments for, among other things, drilling wells, obtaining and processing seismic data and natural gas transportation. At June 30, 2008, these work related commitments totaled $218 million.

7. DERIVATIVE ACTIVITIES

The Company enters into derivative commodity instruments to economically 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. Accordingly, the Company records the net change in the mark-to-market valuation of these positions, as well as all payments and receipts on settled contracts, in current earnings as a component of other income and expenses on the consolidated statement of operations.

During the first quarter of 2008, the Company made the decision to mitigate a portion of its interest rate risk with interest rate swaps, which mitigate exposure to market rate fluctuations by converting variable interest rates (such as those on the Company’s Credit Agreement) to fixed interest rates. Under these swaps, the Company makes payments to, or receives payments from, the counterparties based upon the differential between a specified fixed price and a price related to the three-month LIBOR. The Company has elected to not designate any of its positions for hedge accounting. Accordingly, the Company records the net change in the mark-to-market valuation of these positions, as well as all payments and receipts on settled contracts, in net gain (loss) on derivatives contracts on the consolidated statements of operations. During the second quarter of 2008,

the Company repaid all outstanding borrowings under its Credit Agreement. As a result, the Company made the decision to sell all of its outstanding interest rate swap positions which resulted in a gain of approximately $1.5 million during the second quarter of 2008. This gain is included in net gain (loss) on derivative contracts on the consolidated statements of operations.

At June 30, 2008, the Company had a $8.4 million derivative asset, $3.3 million of which was classified as current, and a $386.8 million derivative liability, $277.0 million of which was classified as current. The Company recorded a net derivative loss of $277.6 million ($229.1 million net unrealized loss and $48.5 million loss for cash paid on settled contracts) for the three months ended June 30, 2008 and a net derivative loss of $420.3 million ($366.6 million net unrealized loss and $53.7 million loss for cash paid on settled contracts) for the six months ended June 30, 2008. 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 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.

At June 30, 2008, the Company had 108 open positions summarized in the tables below: 85 natural gas price collar arrangements, eight natural gas price swap arrangements, five natural gas put options, seven crude oil price swap arrangements and three crude oil collar arrangements.

At December 31, 2007, the Company had 60 open positions: 36 natural gas price collar arrangements, 12 natural gas price swap arrangements, two natural gas put options, seven crude oil price swap arrangements and three crude oil collar arrangements. At December 31, 2007, the Company had a $12.4 million derivative asset, all of which was classified as current, and a $35.1 million derivative liability, $28.2 million of which was classified as current.

Natural Gas

At June 30, 2008, the Company had the following natural gas costless collar positions:


	Collars
		Floors				Ceilings
Period	Volume in Mmbtu’s	Price/ Price Range		Weighted Average Price		Price/ Price Range		Weighted Average Price
July 2008 - December 2008	31,220,000	$	5.00 - $7.25	$	6.92	$	6.45 - $12.25	$	10.51
January 2009 - December 2009	78,470,000		7.00 - 10.00		7.57		9.60 - 16.45		11.77

At June 30, 2008, the Company had the following natural gas swap positions:


	Swaps
Period	Volume in Mmbtu’s	Price/ Price Range		Weighted Average Price
July 2008 - December 2008	5,520,000	$	7.94 - $8.28	$	8.04
January 2009 - December 2009	3,650,000		8.43 - 8.48		8.46
January 2010 - December 2010	3,650,000		8.22 - 8.28		8.25

At June 30, 2008, the Company had the following natural gas put options:


	Floors
Period	Volume in Mmbtu’s	Weighted Average Price
July 2008 - December 2008	1,840,000	$	7.00
January 2009 - December 2009	14,600,000		10.00

The Company has recorded a deferred premium liability of $10.3 million, $5.5 million of which has been classified as current at June 30, 2008 based on a weighted average deferred premium of $0.63 per Mmbtu. The natural gas put option contracts contain deferred premiums that will be paid as the contracts expire.

Crude Oil

At June 30, 2008, the Company had the following crude oil costless collar positions:


	Collars
		Floors				Ceilings
Period	Volume in Bbls	Price/ Price Range		Weighted Average Price		Price/ Price Range		Weighted Average Price
July 2008 - December 2008	398,000	$	34.00 - $70.00	$	64.97	$	45.30 - $85.05	$	80.27

At June 30, 2008, the Company had the following crude oil swap positions:


	Swaps
Period	Volume in Bbls	Price/ Price Range		Weighted Average Price
July 2008 - December 2008	210,000	$	38.10 - $81.70	$	66.42
January 2009 - December 2009	273,750		76.85 - 77.30		77.00
January 2010 - December 2010	273,750		75.10 - 75.55		75.25

8. STOCKHOLDERS’ EQUITY

On February 1, 2008, the Company sold an aggregate of 20.7 million shares of its common stock in an underwritten public offering. The gross proceeds from the sale were approximately $310 million, before deducting underwriting discounts and commissions and estimated expenses, $297 million net.

On May 13, 2008, the Company sold an aggregate of 25.0 million shares of its common stock in an underwritten public offering. Pursuant to the underwriting agreement, the Company granted the underwriters a 30-day option to purchase up to an additional 3,750,000 shares of common stock at the public offering price less underwriting discounts and commissions. The underwriters exercised in full their option to purchase additional shares of common stock which closed on May 23, 2008. The gross proceeds from these sales were approximately $759 million, before deducting underwriting discounts and commissions and estimated expenses, $727 million net.

Stock Appreciation Rights and Stock Options

Certain of the Company’s incentive plans permit awards of stock appreciation rights (SARS) and stock options. 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. Stock options, when exercised, are settled through the payment of the exercise price in exchange for shares of stock underlying the option. SARS, when exercised, are settled without cash in exchange for a net of tax number of shares of common stock valued on the date of settlement. Both SARS and stock options vest one-third annually after the original grant date and have a term of ten years from the date of grant.

During the six months ended June 30, 2008, the Company granted stock options covering 1.0 million shares of common stock to employees of the Company. The stock options have exercise prices ranging from $15.97 to $36.45 with a weighted average price of $18.30. These awards 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, 2008, the

unrecognized compensation expense related to non-vested stock appreciation rights and stock options totaled $5.8 million and will be recognized on a straight line basis over the weighted average remaining vesting period of 1.2 years.

Restricted Stock

During the six months ended June 30, 2008, the Company granted 0.5 million shares of restricted stock to employees of the Company. These restricted shares were granted at prices ranging from $15.97 to $46.31 with a weighted average price of $18.38. 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, 2008, the unrecognized compensation expense related to non-vested restricted stock totaled $11.6 million and will be recognized on a straight line basis over the weighted average remaining vesting period of 1.1 years.

Performance Shares

In conjunction with the Company’s merger with KCS, the Company assumed the KCS 2005 Plan under which performance share awards had been granted. The performance awards provide for a contingent right to receive shares of common stock. The grantee earns 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 fair value of the awards using a monte carlo technique was $10.89 per share. The Company will recognize compensation cost of $1.5 million over the expected service life of the performance share awards whether or not the threshold is achieved. The Company recognized $0.2 million in compensation cost for the six months ended June 30, 2008 and 2007. At June 30, 2008, the unrecognized compensation expense related to non-vested performance shares totaled $0.4 million which will be recognized on a straight line basis over the remaining vesting period of 0.7 years.

Stock Appreciation Rights and Stock Option Assumptions

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


	Six Months Ended June 30,
	2008 ⁽¹⁾		2007
Weighted average value per option granted during the period ⁽²⁾	$	5.35	$	3.58
Assumptions ⁽³⁾:
Stock price volatility		40.0%		38.0%
Risk free rate of return		2.0%		4.4%
Expected term		3.0 years		3.0 years

(1)	The Company’s estimated future forfeiture is approximately 5% based on the Company’s historical forfeiture rate.

(2)	Calculated using the Black-Scholes fair value based method.

(3)	The Company does not pay dividends on its common stock.

9. NET LOSS PER COMMON SHARE

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


	Three Months Ended June 30,					Six Months Ended June 30,
	2008			2007		2008			2007
	(In thousands, except per share amounts)
Basic
Net (loss) income available to common stockholders	$	(92,766	)	$	45,631	$	(148,378	)	$	26,216

Weighted average basic number of shares outstanding		206,490			167,783		195,060			167,546

Basic (loss) income per share	$	(0.45	)	$	0.27	$	(0.76	)	$	0.16

Diluted
Net (loss) income available to common stockholders	$	(92,766	)	$	45,631	$	(148,378	)	$	26,216

Weighted average basic number of shares outstanding		206,490			167,783		195,060			167,546
Common stock equivalent shares representing shares issuable upon exercise of stock options and stock appreciation rights		Anti-dilutive			2,985		Anti-dilutive			2,645
Common stock equivalent shares representing shares issuable upon exercise of warrants		Anti-dilutive			1,345		Anti-dilutive			1,299
Common stock equivalent shares representing shares included upon vesting of restricted shares		Anti-dilutive			—		Anti-dilutive			—

Weighted average diluted number of shares outstanding		206,490			172,113		195,060			171,490

Diluted (loss) income per share	$	(0.45	)	$	0.27	$	(0.76	)	$	0.15

Common stock equivalents, including stock options, SARS, restricted stock and warrants, totaling 9.4 million were not included in the computation of diluted loss (earnings) per share because the effect would have been anti-dilutive due to the net loss for the three and six months ended June 30, 2008. Common stock equivalents of 29,000 and 697,000 shares were not included in the computations of diluted earnings per share for the three and six months ended June 30, 2007 because the grant prices were greater than the average market price of the common shares and the effect would have been anti-dilutive.

10. ADDITIONAL FINANCIAL STATEMENT INFORMATION

Certain balance sheet amounts are comprised of the following:


	June 30, 2008		December 31, 2007
	(In thousands)
Accounts receivable:
Oil and gas sales	$	136,772	$	77,033
Joint interest accounts		71,199		52,210
Other		4,357		18,895

	$	212,328	$	148,138

Prepaid and other:
Prepaid insurance	$	2,199	$	2,690
Prepaid drilling costs		18,435		13,937
Other		2,492		4,392

	$	23,126	$	21,019

Accounts payable and accrued liabilities:
Trade payables	$	44,194	$	25,751
Revenues and royalties payable		122,072		90,967
Accrued capital costs		127,958		117,748
Accrued interest expense		45,188		37,557
Other prepayment liabilities		37,524		10,977
Accrued lease operating expenses		6,257		6,373
Accrued ad valorem taxes payable		3,988		5,578
Accrued employee compensation		6,000		3,468
Accrued Hedging Settlements		5,836		2,028
Other		31,780		31,024

	$	430,797	$	331,471

Item 2.

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

The following discussion of operations for the three and six months ended June 30, 2008 and 2007 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 Annual Report on Form 10-K for the year ended December 31, 2007.

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 onshore in the United States. We focus on properties within our core operating areas which we believe have significant development and exploration opportunities. Our properties are primarily located in the Mid-Continent region, including North Louisiana and the Haynesville Shale, the Fayetteville Shale in the Arkoma basin of Arkansas and in the Western region, including the Permian Basin of West Texas and southeastern New Mexico. We seek to maintain a portfolio of long-lived, lower risk properties in resource-style plays, which typically are characterized by lower geological risk and a large inventory of identified drilling opportunities. We focus on increasing drilling opportunities in our core areas, where we can apply our experience and economies of scale, including the Fayetteville Shale in Arkansas and the Haynesville Shale in North Louisiana. We believe the steps we have taken during 2007 and to date in 2008 will help us grow production and reserves in resource-style, tight-gas areas in North Louisiana and Arkansas.

In the last several months, the Haynesville Shale has become one of the most active new natural gas plays in the United States. This area is defined by a shale formation located approximately 1,500 feet below the Cotton Valley formation at depths ranging from approximately 10,500 feet to 13,000 feet. The formation is as much as 300 feet thick and is composed of an organic rich black shale. It is located across numerous parishes in Northwest Louisiana, primarily in Caddo, Bossier, Red River, DeSoto, Webster and Bienville parishes and also in East Texas, primarily in Harrison, Panola and Shelby counties. Our Elm Grove/Caspiana acreage position is located near what we believe is the center of the play. We believe our acreage in those fields is prospective for Haynesville Shale natural gas production based, in part, on a vertical test well we drilled in 2006 in which over 200 feet of Haynesville Shale was found to be present. We currently own or have entered into agreements to acquire approximately 300,000 net acres in the Haynesville Shale. We have completed our first two operated horizontal wells in the Haynesville Shale. We are currently operating three horizontal drilling rigs and anticipate that to increase to ten operated rigs by year end 2008.

In the first six months of 2008, we produced 49.4 billion cubic feet of natural gas equivalent (Bcfe) compared to production of 58.4 Bcfe for the comparable period of the prior year resulting in a decrease of 9.0 Bcfe due to the sale of our Gulf Coast properties during the fourth quarter of 2007. Natural gas production was 44.9 billion cubic feet (Bcf) and oil production was 750 thousand barrels of oil (Mbbls) for the first six months of 2008. We drilled 328 gross wells (121.7 net) during the first six months of 2008, 322 of which were successful for a success rate of 98%. We reported oil and gas revenues for the six months ended June 30, 2008 of $519.6 million. This represents an increase of $76.8 million as compared to the prior year as increasing oil and natural gas prices more than offset the decrease in our production volumes resulting from the sale of our Gulf Coast properties.

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, 2008 and 2007 were from operating and financing activities. Proceeds from the sale of common stock, the issuance of new senior debt and cash received from operations were offset by long-term debt repayments and 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 future capital expenditures. Our future capital resources and liquidity may depend, in part, on our success in developing the leasehold interests that we acquired during the fourth quarter of 2007 and to date in 2008. We expect to use marketable securities on hand at June 30, 2008, additional borrowings under our Credit Agreement and net proceeds from future capital transactions, if necessary, to provide us with additional financial flexibility to fund our 2008 capital budget and potential acquisitions. See “Results of Operations” below for a review of the impact of prices and volumes on sales.

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


	Six Months Ended June 30,
	2008			2007
	(In thousands)
Cash flows provided by operating activities	$	288,589		$	302,469
Cash flows used in investing activities		(1,534,122	)		(449,023	)
Cash flows provided by financing activities		1,244,796			147,058

Net (decrease) increase in cash	$	(737	)	$	504

Operating Activities. Net cash provided by operating activities for the six months ended June 30, 2008 and 2007 were $288.6 million and $302.5 million, respectively.

Net cash provided by operating activities decreased in 2008 primarily due to changes in working capital associated with the 16% decrease in production volumes as a result of the sale of our Gulf Coast properties during the fourth quarter of 2007 offset by the 38% increase in our average realized natural gas equivalent price compared to the same period in the prior year. We expect to increase our production volumes in 2008 as a result of our 2008 capital program. However, we are unable to predict future production levels or future commodity prices, and, therefore, we cannot provide any assurance about future levels of net cash provided by operating activities.

Investing Activities. The primary driver of cash used in investing activities is capital spending, inclusive of acquisitions and net of dispositions. Cash used in investing activities was $1.5 billion and $449.0 million for the six months ended June 30, 2008 and 2007, respectively.

During the first six months of 2008, we spent $1.4 billion on capital expenditures, of which approximately $1.1 billion related to acquisitions. Our acquisitions were partially funded by the remaining restricted cash that we had deposited with a qualified intermediary following the sale of our Gulf Coast properties to facilitate like-kind exchange transactions. Our program to acquire additional interests and acreage in our key areas, including the Fayetteville Shale in Arkansas, Elm Grove and Terryville fields in Louisiana and the Haynesville Shale in Louisiana, is ongoing. In addition, we participated in the drilling of 328 gross wells in 2008 (121.7 net wells), six of which were dry holes. We spent an additional $31.0 million on other property and equipment during the first six months of 2008 as well, primarily to fund the development of gathering systems in the Fayetteville Shale in Arkansas.

During the first six months of 2008, we used excess funds from our debt and equity offerings discussed below to purchase a net $490 million of marketable securities. These marketable securities have been classified and accounted for as trading securities and will be used primarily to fund our ongoing leasing and acquisition activities in the Haynesville Shale.

During the first six months of 2007, we spent $455.9 million on capital expenditures in conjunction with our acquisition and drilling programs. We acquired additional interests in both the Elm Grove and Terryville fields. In addition, we participated in the drilling of 181 gross wells, of which eight were dry holes, for a success rate of 96%.

The remaining portion of our capital budget for 2008 is expected to be funded from marketable securities on hand at June 30, 2008, additional borrowings under the Credit Agreement, cash flows from operations and net proceeds from future offerings, if necessary. 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 $1.2 billion and $147.1 million for the six months ended June 30, 2008 and 2007, respectively. Cash flows provided by financing activities in 2008 were the result of the sale of a total of 49.5 million shares of common stock and the issuance of $800 million of new senior notes in May and June of 2008.

On February 1, 2008, we sold an aggregate of 20.7 million shares of our common stock in an underwritten public offering. The net proceeds from the sale were approximately $297 million, after deducting underwriting discounts and commissions and estimated expenses.

On May 13, 2008, we sold an aggregate of 25.0 million shares of our common stock in an underwritten public offering. Pursuant to the underwriting agreement, we granted the underwriters a 30-day option to purchase up to an additional 3.75 million shares of common stock at the public offering price less underwriting discounts and commissions. The underwriters exercised in full their option to purchase additional shares of common stock which closed on May 23, 2008. The net proceeds from these sales were approximately $727 million, after deducting underwriting discounts and commissions and estimated expenses.

On May 13, 2008, we issued $500 million aggregate principal amount of the 2015 Notes in a private placement under the Securities Act of 1933, as amended. The net proceeds from the sale of the 2015 Notes were approximately $490 million, after deducting the initial purchasers discounts and estimated offering expenses, including commissions.

On June 19, 2008, we issued an additional $300 million aggregate principal amount of 2015 Notes in a private placement under the Securities Act of 1933, as amended. The net proceeds from the sale of the 2015 Notes were approximately $294 million, after deducting the initial purchaser’s discount and estimated offering expenses.

We seek to maintain excess availability under the Credit Agreement. Capital financing and excess cash flow are used to repay debt to the extent available. During the first six months of 2008, we had net repayments of $570 million primarily due to the sales of common stock and issuances of long term debt discussed above offset by the cash requirements of our drilling and acquisition activities in 2008. As of June 30, 2008, the Credit Agreement had an $800 million borrowing base and no outstanding borrowings.

During the first six months of 2008, we had net borrowings of $228.6 million primarily due to the cash requirements of our drilling program, as compared to net borrowings of $144.2 for the first six months of 2007.

Financing activities for the first six months of 2007 included $2.4 million of cash received on settled derivative contracts that were acquired in conjunction with our acquisition activities.

Contractual Obligations

We have no material changes in our long-term commitments associated with our capital expenditure plans or operating agreements other than those described below. Our level of capital expenditures will vary in future periods depending on the success we experience in our acquisition, 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 for the year ended December 31, 2007, we disclosed that we had 12 drilling rigs under contract for a total commitment over three years of $69.3 million. As of June 30, 2008, we have 28 drilling rigs under contract for a total commitment over three years of $276.7 million.

We have various other contractual commitments pertaining to exploration, development and production activities. We have work related commitments for, among other things, drilling wells, obtaining and processing seismic data and natural gas transportation. At June 30, 2008, these work related commitments totaled $218 million.

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 our annual report on Form 10-K for the year ended December 31, 2007.

Results of Operations

Quarters ended June 30, 2008 and 2007

We reported a net loss of $92.8 million for the three months ended June 30, 2008 compared to net income of $45.6 million for the comparable period in 2007. The decrease in our net income of $138.4 million from the three months ended June 30, 2007 was primarily driven by the change in fair value of derivative instruments due to the change in the forward strip pricing used to value our derivatives which resulted in a loss on derivative contracts before tax of $277.6 million in 2008.


In thousands (except per unit and per Mcfe amounts)	Three Months Ended June 30,						Change
In thousands (except per unit and per Mcfe amounts)	2008			2007			Change
Net (loss) income available to common stockholders	$	(92,766	)	$	45,631		$	(138,397	)
Oil and gas sales		304,633			233,482			71,151
Expenses:
Production:
Lease operating		12,903			17,416			(4,513	)
Workover and other		1,249			1,845			(596	)
Taxes other than income		14,036			16,628			(2,592	)
Gathering, transportation and other		10,944			7,599			3,345
General and administrative:
General and administrative		14,133			13,582			551
Stock-based compensation		3,081			3,398			(317	)
Depletion, depreciation and amortization:
Depletion—Full cost		85,597			99,008			(13,411	)
Depreciation—Other		786			752			34
Accretion expense		311			450			(139	)
Net (loss) gain on derivative contracts		(277,605	)		31,591			(309,196	)
Interest expense and other		(35,154	)		(31,789	)		(3,365	)
Income tax benefit (provision)		58,400			(26,975	)		85,375

Production:
Natural Gas—Mmcf⁽¹⁾		23,413			25,069			(1,656	)
Crude Oil—Mbbl		385			731			(346	)
Natural Gas Equivalent—Mmcfe		25,720			29,454			(3,734	)
Average Daily Production—Mmcfe		283			324			(41	)

*Average price per unit⁽²⁾***:
Gas price per Mcf⁽¹⁾	$	10.99		$	7.51		$	3.48
Oil price per Bbl		117.85			62.07			55.78
Equivalent per Mcfe		11.77			7.94			3.83

Average cost per Mcfe:
Production:
Lease operating		0.50			0.59			(0.09	)
Workover and other		0.05			0.06			(0.01	)
Taxes other than income		0.55			0.56			(0.01	)
Gathering, transportation and other		0.43			0.26			0.17
General and administrative:
General and administrative		0.55			0.46			0.09
Stock-based compensation		0.12			0.12			—
Depletion		3.33			3.36			(0.03	)

(1)	Approximately 3% and 4% of natural gas production represents natural gas liquids (calculated with a 6:1 equivalent ratio) with an average price of $65.71 per Bbl and $41.69 per Bbl for the three months ended June 30, 2008 and 2007, respectively.

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

For the three months ended June 30, 2008, oil and natural gas sales increased $71.2 million from the same period in 2007, to $304.6 million. The increase was primarily due to the increase of $3.83 per Mcfe in our realized average price to $11.77 per Mcfe, which increased revenues by $99 million. The effect of the increase in price was partially offset by a decrease in production of 3,734 Mmcfe due to the sale of our Gulf Coast properties during the fourth quarter of 2007. Decreased production led to an approximate $28 million decrease in revenues for the three months ended June 30, 2008.

Lease operating expenses decreased $4.5 million for the three months ended June 30, 2008. The decrease was primarily due to the decrease in production volumes as a result of the sale of our Gulf Coast properties during the fourth quarter of 2007. On a per unit basis, lease operating expenses decreased from $0.59 per Mcfe in 2007 to $0.50 per Mcfe in 2008. This decrease on a per unit basis is primarily due to the sale of our higher lease operating cost Gulf Coast properties during the fourth quarter of 2007 as well as our continued cost control efforts to lower our lease operating expense.

Workover expenses decreased $0.6 million for the three months ended June 30, 2008 compared to the three months ended June 30, 2007. The decrease was primarily due to the sale of our Gulf Coast properties during the fourth quarter of 2007 which historically had a higher amount of activity compared to our ongoing operations.

Taxes other than income decreased $2.6 million for the three months ended June 30, 2008 as compared to the same period in 2007. The largest components of taxes other than income are production and severance taxes which are generally assessed as either a percentage of gross oil and natural gas sales or as a fixed rate based on production. As a percentage of oil and gas sales, taxes other than income decreased from 7% in 2007 to 5% in 2008. This decrease as a percentage of revenue is primarily attributable to the sale of our Gulf Coast properties and the increase in production associated with our production in Louisiana and Arkansas.

Gathering, transportation and other expense increased $3.3 million, or $0.17 per Mcfe, for the three months ended June 30, 2008 as compared to the same period in 2007. This increase was primarily due to an increase in production in the Fayetteville Shale which has higher gathering, transportation and other costs.

General and administrative expense for the three months ended June 30, 2008 increased $0.6 million as compared to the same period in 2007. This increase was attributable to a general increase in office expenses offset by a decrease in payroll and employee benefits due to the headcount reduction associated with the sale of our Gulf Coast properties. General and administrative expense increased on a per Mcfe basis from $0.46 per Mcfe in 2007 to $0.55 per Mcfe in 2008 as the decrease in production associated with the sale of our Gulf Coast properties during the fourth quarter of 2007 was greater than the cost savings we achieved as well as the incurrence of costs in 2008 associated with the debt and equity offerings.

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. Depletion expense decreased $13.4 million for the three months ended June 30, 2008 from the same period in 2007, to $85.6 million. This decrease was primarily attributable to the decrease in production volumes due to the sale of our Gulf Coast properties during the fourth quarter of 2007 coupled with the proceeds from such sale being treated as an adjustment to our full cost pool. On a per unit basis, depletion expense decreased $0.03 per Mcfe to $3.33 per Mcfe.

We enter into derivative commodity instruments to economically 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 value of these derivative contracts in the consolidated statement of operations. At June 30, 2008, we had a $8.4 million derivative asset, $3.3 million of which was classified as current, and a $386.8 million derivative liability, $277.0 million of which was classified as current. The Company recorded a net derivative

loss of $277.6 million ($229.1 million net unrealized loss and $48.5 million loss for cash paid on settled contracts) for the three months ended June 30, 2008 compared to 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) in the prior year. This increase in our net derivative loss is primarily attributable to the recent increase in the forward strip pricing used to value our derivatives.

Interest expense and other increased $3.4 million for the three months ended June 30, 2008 compared to the same period in 2007. Interest expense increased $5.7 million due to the issuance of $800 million of new long-term debt in 2008. In addition, we withdrew our proposed Master Limited Partnership public offering during the second quarter of 2008 and expensed the related costs of $3.4 million which is included in interest expense and other. These items were partially offset by a reduction in interest expense associated with our Credit Agreement of $3.9 million from the prior year due to the decrease in our outstanding balance as well as interest income of $2.2 million primarily attributable to our investment of proceeds from the sale of our Gulf Coast properties as well as the proceeds we received from the issuance of common stock and long-term debt during 2008.

Income tax expense for the three months ended June 30, 2008 decreased $85.4 million from the prior year. The decrease in income tax expense from prior year was primarily due to our pre-tax loss of $151.2 million for the three months ended June 30, 2008 compared to our pre-tax income of $72.6 million in 2007. The effective tax rates for the three months ended June 30, 2008 and 2007 were 38.63% and 37.2%, respectively. The increase in our effective rate is primarily due to an increase in the state effective tax rate generated by a shift in the composition of assets among various states.

Six Months ended June 30, 2008 and 2007

We reported a net loss of $148.4 million for the six months ended June 30, 2008 compared to net income of $26.2 million for the comparable period in 2007. The decrease in our net income of $174.6 million from the six months ended June 30, 2007 was primarily driven by the change in fair value of derivative instruments due to the change in the forward strip pricing used to value our derivatives which resulted in a loss on derivative contracts before tax of $420.3 million in 2008.


In thousands (except per unit and per Mcfe amounts)	Six Months Ended June 30,						Change
In thousands (except per unit and per Mcfe amounts)	2008			2007			Change
Net (loss) income available to common stockholders	$	(148,378	)	$	26,216		$	(174,594	)
Oil and gas sales		519,571			442,725			76,846
Expenses:
Production:
Lease operating		25,297			33,292			(7,995	)
Workover and other		1,786			4,022			(2,236	)
Taxes other than income		25,000			30,278			(5,278	)
Gathering, transportation and other		20,467			15,023			5,444
General and administrative:
General and administrative		27,689			26,296			1,393
Stock-based compensation		5,679			6,285			(606	)
Depletion, depreciation and amortization:
Depletion—Full cost		167,670			193,708			(26,038	)
Depreciation—Other		1,558			1,446			112
Accretion expense		593			894			(301	)
Net loss on derivative contracts		(420,346	)		(27,342	)		(393,004	)
Interest expense and other		(62,691	)		(62,539	)		(152	)
Income tax benefit (provision)		90,827			(15,384	)		106,211

Production:
Natural Gas—Mmcf⁽¹⁾		44,936			49,595			(4,659	)
Crude Oil—Mbbl		750			1,479			(729	)
Natural Gas Equivalent—Mmcfe		49,433			58,468			(9,035	)
Average Daily Production—Mmcfe		272			323			(51	)

Average price per unit *⁽²⁾*:
Gas price per Mcf⁽¹⁾	$	9.72		$	7.17		$	2.55
Oil price per Bbl		106.66			59.05			47.61
Equivalent per Mcfe		10.45			7.58			2.87

Average cost per Mcfe:
Production:
Lease operating		0.51			0.57			(0.06	)
Workover and other		0.04			0.07			(0.03	)
Taxes other than income		0.51			0.52			(0.01	)
Gathering, transportation and other		0.41			0.26			0.15
General and administrative:
General and administrative		0.56			0.45			0.11
Stock-based compensation		0.11			0.11			—
Depletion		3.39			3.31			0.08

(1)	Approximately 3% and 4% of natural gas production represents natural gas liquids (calculated with a 6:1 equivalent ratio) with an average price of $63.78 per Bbl and $37.58 per Bbl for the six months ended June 30, 2008 and 2007, respectively.

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

For the six months ended June 30, 2008, oil and natural gas sales increased $76.8 million from the same period in 2007, to $519.6 million. The increase was primarily due to the increase of $2.87 per Mcfe in our equivalent realized average price to $10.45, which increased revenues by $142 million. The effect of the increase in price was partially offset by a decrease in production of 9,035 Mmcfe due to the sale of our Gulf Coast properties during the fourth quarter of 2007. Decreased production led to an approximate $65 million decrease in revenues for the six months ended June 30, 2008.

Lease operating expenses decreased $8.0 million for the six months ended June 30, 2008. The decrease was primarily due to the decrease in production volumes as a result of the sale of our Gulf Coast properties during the fourth quarter of 2007. On a per unit basis, lease operating expenses decreased from $0.57 per Mcfe in 2007 to $0.51 per Mcfe in 2008. This decrease on a per unit basis is primarily due to the sale of our higher lease operating cost Gulf Coast properties during the fourth quarter of 2007 as well as our continued cost control efforts to lower our lease operating expense.

Workover expenses decreased $2.2 million for the six months ended June 30, 2008 compared to the six months ended June 30, 2007. The decrease was primarily due to the sale of our Gulf Coast properties during the fourth quarter of 2007 which historically had a higher amount of activity compared to our ongoing operations.

Taxes other than income decreased $5.3 million for the six months ended June 30, 2008 as compared to the same period in 2007. The largest components of taxes other than income are production and severance taxes which are generally assessed as either a percentage of gross oil and natural gas sales or as a fixed rate based on production. As a percentage of oil and gas sales, taxes other than income decreased from 7% in 2007 to 5% in 2008. This decrease as a percentage of revenue is primarily attributable to the sale of our Gulf Coast properties and the increase in production associated with our production in Louisiana and Arkansas.

Gathering, transportation and other expense increased $5.4 million, or $0.15 per Mcfe, for the six months ended June 30, 2008 as compared to the same period in 2007. This increase was primarily due to an increase in production in the Fayetteville Shale which has higher gathering, transportation and other costs.

General and administrative expense for the six months ended June 30, 2008 increased $1.4 million as compared to the same period in 2007 to $27.7 million. This increase was attributable to a general increase in office expenses and certain costs associated with the recent debt and equity offerings offset by a decrease in payroll and employee benefits due to the headcount reduction associated with the sale of our Gulf Coast properties. General and administrative expense increased on a per Mcfe basis from $0.45 per Mcfe in 2007 to $0.56 per Mcfe in 2008 as the decrease in production associated with the sale of our Gulf Coast properties during the fourth quarter of 2007 was greater than the cost savings we achieved.

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. Depletion expense decreased $26.0 million for the six months ended June 30, 2008 from the same period in 2007, to $167.7 million. This decrease was primarily attributable to the decrease in production volumes due to the sale of our Gulf Coast properties during the fourth quarter of 2007 coupled with the proceeds from such sale being treated as an adjustment to our full cost pool. On a per unit basis, depletion expense increased $0.08 per Mcfe to $3.39 per Mcfe. This increase on a per unit basis is primarily due to production decreases outweighing the overall reduction in our full cost pool as a result of the sale of our Gulf Coast properties.

derivative liability, $277.0 million of which was classified as current. The Company recorded a net derivative loss of $420.3 million ($366.6 million net unrealized loss and $53.7 million loss for cash paid on settled contracts) for the six months ended June 30, 2008 compared to 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) in the prior year. This increase in our net derivative loss is primarily attributable to the recent increase in the forward strip pricing used to value our derivatives.

Interest expense and other was $63 million for the six months ended June 30, 2008 and 2007. Interest expense increased $5.7 million due to the issuance of $800 million of new long-term debt in 2008. In addition, we withdrew our proposed Master Limited Partnership public offering during the second quarter of 2008 and expensed the related costs of $3.4 million which is included in interest expense and other. These items were offset by a reduction in interest expense associated with the Credit Agreement of $3.0 million from the prior year due to the decrease in our outstanding balance as well as interest income of $5.9 million primarily attributable to our investment of proceeds from the sale of our Gulf Coast properties as well as the proceeds we received from the issuance of common stock and long-term debt during 2008.

Income tax expense for the six months ended June 30, 2008 decreased $106.2 million from the prior year. The decrease in income tax expense from prior year was primarily due to our pre-tax loss of $239.2 million for the six months ended June 30, 2008 compared to our pre-tax income of $41.6 million in 2007. The effective tax rates for the six months ended June 30, 2008 and 2007 were 38.0% and 37.0%, respectively. The increase in our effective rate is primarily due to an increase in the state effective tax rate generated by a shift in the composition of assets among various states.

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.

Historically, we have also been exposed to interest rate risk on our variable interest rate debt. As a result, during the first quarter of 2008, we made the decision to implement a risk management policy to mitigate a portion of this risk as we expect interest rates to continue to be volatile and unpredictable. If interest rates increase, our interest expense would increase and our available cash flow would decrease. Our risk management policy provides for the use of interest rate swaps to reduce the exposure to market rate fluctuations by converting variable interest rates to fixed interest rates. We can be exposed to market risk on open contracts, to the extent of

changes in LIBOR. However, the market risk exposure on these contracts is generally offset by the increase or decrease in our interest expense. Further, if our counterparties defaulted, this protection might be limited as we might not receive the benefits of the contracts. Although we do not have any variable interest rate debt at June 30, 2008, we will continue to monitor our risk exposure as we incur future indebtedness at variable interest rates and will look to continue our risk management policy as situations present themselves.

Interest Sensitivity

Historically, we have been exposed to interest rate risk exposure primarily from fluctuations in short-term rates, which are LIBOR and ABR based. These fluctuations can cause reductions of earnings or cash flows due to increases in the interest rates that we have historically paid on these obligations. At June 30, 2008, total debt excluding related discounts and premiums was $1.8 billion which bears interest at a weighted average fixed interest rate of 8.3% per year. The Company does not currently have any long-term debt that bears interest at floating or market interest rates. If we incur future indebtedness which bears interest at variable rates, fluctuations in market interest rates could cause our annual interest costs to fluctuate.

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, 2008 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, if any, 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 risk factors described in the Company’s annual report on Form 10-K for the year ended December 31, 2007 other than those listed below.

Part of our strategy involves exploratory drilling, including drilling in new or emerging plays. As a result, our drilling results in these areas are uncertain.

The results of our exploratory drilling in new or emerging plays, such as the Haynesville Shale and the Fayetteville Shale, are more uncertain than drilling results in areas that are developed and have established production. Since new or emerging plays and new formations have limited or no production history, we are less

able to use past drilling results in those areas to help predict our future drilling results. To the extent we are unable to execute our expected drilling program in these areas, because of capital constraints, lease expirations, access to adequate gathering systems or pipeline, take-away capacity, availability of drilling rigs and other services, or otherwise, and/or natural gas and oil prices decline, the return on our investment in these areas may not be as attractive as we anticipate and our common stock price may decrease. We could incur material write-downs of unevaluated properties, and the value of our undeveloped acreage could decline in the future if our drilling results are unsuccessful.

The results of our planned exploratory drilling in the Haynesville Shale, a newly emerging play with limited drilling and production history, are subject to more uncertainties than our drilling program in the more established shallower Lower Cotton Valley formations and may not meet our expectations for reserves or production.

We have recently begun drilling wells in the Haynesville Shale. Part of our drilling strategy to maximize recoveries from the Haynesville Shale involves the drilling of horizontal wells using completion techniques that have proven successful in other shale formations. Our experience with horizontal drilling of the Haynesville Shale to date, as well as the industry’s drilling and production history in the formation, is limited. The ultimate success of these drilling and completion strategies and techniques in this formation will be better evaluated over time as more wells are drilled and production profiles are better established. Accordingly, the results of our future drilling in the emerging Haynesville Shale play are more uncertain than drilling results in the shallower Lower Cotton Valley horizons with established reserves and production histories.

We have substantial indebtedness and may incur substantially more debt. Any failure to meet our debt obligations would adversely affect our business and financial condition.

We have incurred substantial debt amounting to approximately $1.8 billion as of June 30, 2008. As a result of our indebtedness, we will need to use a portion of our cash flow to pay interest, which will reduce the amount we will have available to finance our operations and other business activities and could limit our flexibility in planning for or reacting to changes in our business and the industry in which we operate. Any indebtedness which may be outstanding in the future under our Credit Agreement is at a variable interest rate, and so a rise in interest rates will generate greater interest expense to the extent we do not have applicable interest rate fluctuation hedges. The amount of our debt may also cause us to be more vulnerable to economic downturns and adverse developments in our business.

We may incur substantially more debt in the future. The indentures governing our outstanding senior notes contain restrictions on our incurrence of additional indebtedness. These restrictions, however, are subject to a number of qualifications and exceptions, and under certain circumstances, we could incur substantial additional indebtedness in compliance with these restrictions. Moreover, these restrictions do not prevent us from incurring obligations that do not constitute indebtedness under the indentures. As of June 30, 2008, we had approximately $800 million of additional borrowing capacity under our Credit Agreement, subject to specific requirements, including compliance with financial covenants. To the extent we incur indebtedness, other than under our Credit Agreement, our borrowing base under our Credit Agreement will be reduced by $0.25 for each additional dollar of new debt. Our borrowing base is subject to Semi-Annual Redeterminations. We expect to complete a Redetermination during the third quarter of 2008.

Our ability to meet our debt obligations and other expenses will depend on our future performance, which will be affected by financial, business, economic, regulatory and other factors, many of which we are unable to control. If our cash flow is not sufficient to service our debt, we may be required to refinance the debt, sell assets or sell additional shares of common stock on terms that we may not find attractive if it may be done at all. Further, our failure to comply with the financial and other restrictive covenants relating to our indebtedness could result in a default under that indebtedness, which could adversely affect our business, financial condition and results of operations.

We may not be able to drill wells on a substantial portion of our properties.

Our drilling activities and future drilling budget will depend on drilling results, oil and natural gas prices, the availability of capital, drilling and production costs, availability of drilling services and equipment, lease expirations, gathering system and transportation constraints, regulatory approval and other factors. In addition, any drilling activities we are able to conduct on these locations may not be successful or result in our ability to add additional proved reserves to our overall proved reserves, which could have a material adverse effect on our future business and results of operations.

We may have difficulty financing our planned capital expenditures which could adversely affect our growth.

We have experienced, and expect to continue to experience, substantial capital expenditure and working capital needs, particularly as a result of our drilling and leasehold acquisition program, particularly in the Haynesville Shale. Our budgeted capital expenditures for 2008 are expected to exceed substantially the net cash generated by our operations. In addition, we intend to continue to increase our acreage position in the Haynesville Shale, which will require substantial additional capital in addition to the capital necessary to drill on our existing acreage. We expect to use borrowings under our Credit Agreement and proceeds from future equity or debt offerings, if necessary, to fund capital expenditures that are in excess of our cash flow and cash on hand. Our ability to borrow under our Credit Agreement is subject to certain conditions and subject to our borrowing base. Additionally, our ability to complete future equity offerings is limited by the availability of authorized common stock under our certificate of incorporation and by general market conditions. If we are not able to borrow sufficient amounts under our Credit Agreement and/or are unable to raise sufficient capital to fund our capital expenditures, we may be required to curtail our drilling, development, land acquisition and other activities and/or be forced to sell some of our assets on an untimely or unfavorable basis. Any such curtailment or sale could have a material adverse effect on our results and future operations.

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds

The following table sets forth certain information with respect to the surrender of our common stock by employees in exchange for the payment of certain tax obligations during the three months ended June 30, 2008.


	Total Number of Shares Purchased ⁽¹⁾	Average Price Paid Per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs
April 2008	1,648	$	21.98	—	—
May 2008	1,289	$	25.95	—	—
June 2008	270	$	39.69	—	—

(1)

All of the shares were surrendered by employees in exchange for the payment of tax withholding upon the vesting of restricted stock awards. The acquisition of the surrendered shares was not part of a publicly announced program to repurchase shares of our common stock, nor were they considered as or accounted for as Treasury shares.

Item 3.

Defaults Upon Senior Securities

None.

Item 4.

Submission of Matters to a Vote of Security Holders

Our annual meeting of stockholders was held on May 20, 2008 in Houston, Texas for the purpose of voting on two proposals, both of which were approved.

The first of those proposals related to the election of individuals to serve as Class I directors of Petrohawk for three-year terms expiring in 2011.

1. The three directors elected and the tabulation of votes (both in person and by proxy) was as follows:


Nominees for Directors	Votes For	Witheld
Floyd C. Wilson	174,062,646	2,928,600
Tucker S. Bridwell	176,082,810	908,436
Gary A. Merriman	175,637,814	1,353,432

Continuing directors for Petrohawk after the annual meeting include: Thomas R. Fuller, Robert G. Raynolds, Christopher A. Viggiano, James L. Irish III, Robert C. Stone, Jr., and James W. Christmas.

2. The second proposal upon which our stockholders voted was to ratify the appointment of Deloitte & Touche LLP as the Company’s independent auditor for the year ending December 31, 2008. The tabulation of votes (both in person and by proxy) on the second proposal was a follows:


For	Against	Abstain	Broker Non-Votes
175,801,778	1,117,971	51,494	20,003

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
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).


Exhibit No		Description
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).

4.10		Second Supplemental Indenture dated August 3, 2007 among Petrohawk Energy Corporation, One TEC, LLC, One TEC Operating, LLC, Bison Ranch, LLC, the parties named therein as existing guarantors and U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit 4.10 to our Quarterly Report on Form 10-Q filed November 8, 2007).

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

4.12		Registration Rights Agreement, dated May 13, 2008, among the Company, the subsidiary guarantors named therein, and Lehman Brothers Inc., on behalf of Lehman Brothers Inc., J.P. Morgan Securities Inc., Merrill Lynch, Pierce, Fenner & Smith Incorporated, BNP Paribas Securities Corp., Credit Suisse Securities (USA) LLC, Banc of America Securities LLC, Citigroup Global Markets Inc., BMO Capital Markets Corp., RBC Capital Markets Corporation, and Wells Fargo Securities, LLC (Incorporated by reference to Exhibit 4.2 to our Current Report on Form 8-K filed May 15, 2008).


Exhibit No		Description
10.1		Sixth 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 (the “Lenders”), 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 (Incorporated by reference to Exhibit 10.2 to our Quarterly Report on Form 10-Q filed May 6, 2008).

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 6, 2008	By:	/s/ Floyd C. Wilson
		Floyd C. Wilson Chairman of the Board, President and Chief Executive Officer

	By:	/s/ Mark J. Mize
		Mark J. Mize Executive Vice President, Chief Financial Officer and Treasurer

	By:	/s/ C. Byron Charboneau
		C. Byron Charboneau Vice President, Chief Accounting Officer and Controller

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