Edgar Filing: PETROHAWK ENERGY CORP

Form 10-Q

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 March 31, 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 ¨		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 May 2, 2008 the Registrant had 193,003,517 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 months ended March 31, 2008 and 2007	4

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

	Consolidated statements of cash flows for the three months ended March 31, 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	28

ITEM 4.	Controls and procedures	29

PART II. OTHER INFORMATION

ITEM 1.	Legal proceedings	30

ITEM 1A.	Risk factors	30

ITEM 2.	Unregistered sales of equity securities and use of proceeds	30

ITEM 3.	Defaults upon senior securities	30

ITEM 4.	Submission of matters to a vote of security holders	30

ITEM 5.	Other information	30

ITEM 6.	Exhibits	31

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 may be identified by use of terms such as “expect,” “anticipate,” “estimate,” “plan,” “believe,” “intend,” “will,” “continue,” “potential,” “should,” “could” and similar words and expressions, although some forward-looking statements may be expressed differently. You should be aware that our actual results could differ materially from those contained in the forward-looking statements. You should consider carefully the statements under the “Risk Factors” section of this report and other sections of this report, as well as those described in 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 and in our higher risk exploratory 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 and expense cost escalations;

•

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 employees;

•

our ability to obtain goods and services, such as drilling rigs and tubulars, 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 attributable to us or persons acting on our behalf are expressly qualified in their entirety by the cautionary statements in this paragraph and elsewhere in this document. Other than as required under the securities laws, we do not assume a duty to update these forward-looking statements, whether as a result of new information, subsequent events or circumstances, changes in expectations or otherwise.

PART I. FINANCIAL INFORMATION

Item 1.

Condensed Consolidated Financial Statements (unaudited)

PETROHAWK ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(In thousands, except per share amounts)


	Three Months Ended March 31,
	2008			2007
Operating revenues:
Oil and gas	$	214,938		$	209,243
Operating expenses:
Production:
Lease operating		12,394			15,876
Workover and other		537			2,177
Taxes other than income		10,964			13,650
Gathering, transportation and other		9,523			7,424
General and administrative		16,154			15,601
Depletion, depreciation and amortization		83,127			95,838

Total operating expenses		132,699			150,566

Income from operations		82,239			58,677
Other expenses:
Net loss on derivative contracts		(142,741	)		(58,933	)
Interest expense and other		(27,537	)		(30,750	)

Total other expenses		(170,278	)		(89,683	)

Loss before income taxes		(88,039	)		(31,006	)
Income tax benefit		32,427			11,591

Net loss	$	(55,612	)	$	(19,415	)

Net loss per share of common stock:
Basic	$	(0.30	)	$	(0.12	)

Diluted	$	(0.30	)	$	(0.12	)

Weighted average shares outstanding:
Basic		183,629			167,306

Diluted		183,629			167,306

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)


	March 31, 2008			December 31, 2007
Current assets:
Cash	$	7,199		$	1,812
Accounts receivable		174,293			148,138
Current portion of deferred income taxes		50,285			5,855
Receivables from derivative contracts		135			12,369
Prepaid expenses and other		22,197			21,019

Total current assets		254,109			189,193

Oil and gas properties (full cost method):
Evaluated		3,685,558			3,247,304
Unevaluated		830,074			677,565

Gross oil and gas properties		4,515,632			3,924,869
Less - accumulated depletion		(851,270	)		(769,197	)

Net oil and gas properties		3,664,362			3,155,672

Other operating property and equipment:
Gross other operating property and equipment		33,714			18,940
Less - accumulated depreciation		(7,609	)		(6,838	)

Net other operating property and equipment		26,105			12,102

Other noncurrent assets:
Goodwill		933,920			933,945
Debt issuance costs, net of amortization		11,852			12,052
Receivables from derivative contracts		184			—
Restricted cash (Note 2)		—			269,837
Note receivable		99,010			96,098
Other		3,277			3,540

Total assets	$	4,992,819		$	4,672,439

Current liabilities:
Accounts payable and accrued liabilities	$	305,225		$	331,471
Liabilities from derivative contracts		119,325			28,198
Current portion of long-term debt		2,266			828

Total current liabilities		426,816			360,497

Long-term debt		1,560,849			1,595,127
Liabilities from derivative contracts		39,814			6,915
Asset retirement obligations		25,947			23,800
Deferred income taxes		677,224			674,968
Other noncurrent liabilities		2,449			2,235
Commitments, contingencies and litigation (Note 6)
Stockholders’ equity:
Common stock: 300,000,000 shares of $.001 par value authorized; 192,891,088 and 171,220,817 shares issued and outstanding at March 31, 2008 and December 31, 2007, respectively		193			171
Additional paid-in capital		2,177,929			1,871,516
Retained earnings		81,598			137,210

Total stockholders’ equity		2,259,720			2,008,897

Total liabilities and stockholders’ equity	$	4,992,819		$	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)


	Three Months Ended March 31,
	2008			2007
Cash flows from operating activities:
Net loss	$	(55,612	)	$	(19,415	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depletion, depreciation and amortization		83,127			95,838
Income tax benefit		(32,427	)		(11,591	)
Stock-based compensation		2,598			2,888
Net unrealized loss on derivative contracts		137,515			74,971
Net realized gain on derivative contracts acquired		—			(2,440	)
Other		(1,465	)		1,355
Change in assets and liabilities, net of acquisitions:
Accounts receivable		(38,769	)		785
Prepaid expenses and other		(1,178	)		2,526
Accounts payable and accrued liabilities		(33,081	)		(9,437	)
Other		477			(208	)

Net cash provided by operating activities		61,185			135,272

Cash flows from investing activities:
Oil and gas capital expenditures		(150,405	)		(224,496	)
Acquisition of oil and gas properties		(428,306	)		(1,574	)
Decrease in restricted cash		269,837			—
Other operating property and equipment expenditures		(14,438	)		(1,363	)
Other		—			1,101

Net cash used in investing activities		(323,312	)		(226,332	)

Cash flows from financing activities:
Proceeds from exercise of options		6,307			1,400
Proceeds from issuance of common stock		310,500			—
Offering costs		(13,792	)		—
Proceeds from borrowings		380,000			249,000
Repayment of borrowings		(415,000	)		(161,415	)
Net realized gain on derivative contracts acquired		—			2,440
Other		(501	)		(14	)

Net cash provided by financing activities		267,514			91,411

Net increase in cash		5,387			351
Cash at beginning of period		1,812			5,593

Cash at end of period	$	7,199		$	5,944

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 current earnings as a component of other income and expenses 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 senior revolving credit facility 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 statement of operations.

Recently Issued Accounting Pronouncements

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 financial position, financial performance, and 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 May 2007, the FASB issued Staff Position (FSP) No. FIN 48-1, Definition of Settlement in FASB Interpretation No. 48, (FIN 48-1) which amends Financial Interpretation (FIN) No. 48, Accounting for Uncertainty in Income Taxes—an Interpretation of FASB 109 (FIN 48) and provides guidance concerning how an entity should determine whether a tax position is “effectively,” rather than the previously required “ultimately,” settled for the purpose of recognizing previously unrecognized tax benefits. The guidance in FIN 48-1 became effective upon the initial January 1, 2007 adoption of FIN 48. Companies that have not applied this guidance must retroactively apply the provisions of this FSP to the date of the initial adoption of FIN 48. The Company adopted FIN 48-1 and no retroactive adjustments were necessary.

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 guidance in FIN 39-1 became effective for fiscal years beginning after November 15, 2007, with early application allowed. The Company adopted FIN 39-1 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 hedge against the variability in cash flows associated with the forecasted sale of its anticipated future oil and natural gas production. The Company generally 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 sheet, with the changes in the fair value included in statement 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 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 March 31, 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	March 31, 2008
Recurring Fair Value Measures	Level 1		Level 2		Level 3		Total
	(In thousands)
Assets
Receivables from derivative contracts	$	—	$	319	$	—	$	319

Liabilities
Liabilities from derivative contracts	$	—	$	159,139	$	—	$	159,139

Derivatives listed above include interest rate swaps, commodity swaps, options and collars that are carried at fair value. All of the fair value amounts included in current period earnings 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 and interest rates based on quoted markets prices and prospective volatility factors related to changes in the forward curves.

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.

The Company has continued to increase its position in the Fayetteville Shale through its ongoing leasing activities and by acquiring interests that it believes to be strategically located, the vast majority of which represent undeveloped properties. 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. On February 12, 2008, the Company completed an additional acquisition in the Elm Grove Field for approximately $19 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 (the Note). The Note matures five years and ninety-one days from the closing date and bears interest at 12% per annum payable in kind at the purchaser’s option. The purchaser may redeem the Note at any time prior to one year from November 30, 2007 for $100 million plus accrued and unpaid interest. If the redemption occurs prior to 150 days after November 30, 2007, accrued interest will 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. At March 31, 2008 and December 31, 2007, $1.0 million and $3.9 million, respectively, of the discount remained and is being amortized by the Company over the first 150 days of the Note. On April 28, 2008, the Company received the $100 million payment. Refer to Note 11, “Subsequent Events” for more details.

In conjunction with the closing of this sale, we 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 though the SEC permits, under certain circumstances, 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 March 31, 2008 and December 31, 2007 consisted of the following:


	March 31, 2008		December 31, 2007
	(In thousands)
Senior revolving credit facility	$	535,000	$	570,000
9¹/8% $775 million senior notes⁽¹⁾		763,137		762,934
7¹/8% $275 million senior notes⁽²⁾		262,458		261,939
9⁷/8% senior notes		254		254

	$	1,560,849	$	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 $6.7 million and $6.9 million discount at March 31, 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 $1.1 million premium at March 31, 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 $9.9 million and $10.4 million discount at March 31, 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.

Amounts related to our deferred premiums on derivatives of $2.3 million and $0.8 million have been classified as current at March 31, 2008 and December 31, 2007, respectively, and have been excluded from the long-term debt table above.

Senior Revolving Credit Facility

On October 15, 2007, the Company entered into the Fourth Amendment (the Fourth Amendment) to Second Amended and Restated Senior Revolving Credit Agreement dated as of July 12, 2006 among Petrohawk, 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 Fourth Amendment, the facility borrowing base was increased to $900 million until the earlier of (a) the consummation of the sale of the Gulf Coast properties or (b) the next borrowing base redetermination date. The Company may, at its option, request the borrowing base be increased by $100 million for every $275 million of the 9¹/8% senior notes due 2013 and the 7¹/8% senior notes due 2012 redeemed or repurchased. Effective November 30, 2007, the Company’s borrowing base was decreased to $675 million. On February 5, 2008, the Company entered into an amendment to its senior revolving credit facility to increase the borrowing base from $675 million to $1 billion (the Fifth Amendment).

Amounts outstanding 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. 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. Refer to Note 7, “Derivative Activities” for more details.

The senior revolving credit facility 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 senior revolving credit facility to current liabilities) of not less than 1.0 to 1.0. In addition, the senior revolving credit facility 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 to no more than 85% of anticipated projected production from proved, developed producing oil and gas properties for each month during the term of the hedging contract. At March 31, 2008, the Company’s hedging arrangements exceeded the maximum amount of anticipated projected production of 85%. On May 5, 2008, the Company entered into an amendment which redefined the covenant limiting commodities hedging transactions as described below, permits us to incur additional long-term debt in connection with our proposed equity and long-term debt offerings, subject to a reduction in our borrowing base (the Sixth Amendment). See Note 11, “Subsequent Events”, for more details.

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 7¹/8% senior notes due 2012. The 2012 Notes are guaranteed on an unsubordinated, unsecured basis by all of the Company’s current subsidiaries, including the subsidiaries of KCS that the Company acquired in the merger. Interest on the 2012 Notes is payable semi-annually, on each April 1 and October 1. On or after April 1, 2008, the Company may redeem all or a portion of the 2012 Notes. If the notes are redeemed during any 12-month period beginning on April 1 of the year indicated below, the Company must pay 100% of the principal amount, plus a specified premium (expressed as percentages of principal amount) plus accrued and unpaid interest thereon, if any, to the applicable redemption date:


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

At March 31, 2008, the Company was in compliance with all of its debt covenants under the 7¹/8% Senior 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 $9.9 million at March 31, 2008.

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

9¹/8% Senior Notes

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

The 2013 Notes bear interest at the rate of 9.125% per annum, payable semi-annually on January 15 and July 15 of each year, commencing January 15, 2007. The 2013 Notes mature on July 15, 2013. The 2013 Notes are senior unsecured obligations of the Company and rank equally with all of its current and future senior indebtedness, including the 2012 Notes. The 2013 Notes rank effectively subordinate to the Company’s secured debt to the extent of the collateral, including secured debt under the revolving credit facility, and senior to any future subordinated indebtedness. The 2013 Notes are jointly and severally guaranteed on a senior unsecured basis by the Company’s subsidiaries, including, pursuant to the 2013 First Supplemental Indenture, the KCS subsidiaries acquired in the Company’s merger with KCS.

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

In addition, on or before July 15, 2010, the Company may redeem all or part of the 2013 Notes upon not less than 30 nor more than 60 days’ notice, at a redemption price equal to the sum of the principal amount, plus accrued and unpaid interest, if any, to the redemption date, plus the make whole premium at the redemption date.

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


Year		Percentage
2010		104.563
2011		102.281
2012		100.000

The Company may be required to offer to repurchase the 2013 Notes at a purchase price of 101% of the principal amount, plus accrued and unpaid interest, if any, to the redemption date, in the event of a change of control as defined in the 2013 Indenture. Additionally, the Company may be required to offer to repurchase the 2013 Notes and, to the extent required by the terms thereof, all other indebtedness (as defined in the 2013 Indenture) that is pari passu with the 2013 Notes at a purchase price of 100% of the principal amount (or accreted value in the case of any such other pari passu indebtedness issued with a significant original issue discount) plus accrued and unpaid interest, if any, to the date of purchase, in the event net proceeds from assets sales are not applied as required by the 2013 Indenture.

The 2013 Indenture contains covenants that, among other things, restrict or limit the ability of the Company and its subsidiaries to: 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.

The Company issued the 2013 Notes in two tranches, $650 million on July 12, 2006 and $125 million on July 27, 2006. The additional $125 million in 2013 Notes were issued pursuant to the same Indenture at 101.125% of the face amount. The Company applied the net proceeds from the sale of the additional 2013 Notes to repay indebtedness outstanding under its revolving credit facility. At March 31, 2008, the Company is in compliance with all of its debt covenants relating to the 2013 Senior Notes.

In conjunction with the issuance of the $650 million 2013 Notes, the Company recorded a discount of $8.2 million to be amortized over the remaining life of the notes utilizing the effective interest rate method. The

remaining unamortized discount was $6.7 million at March 31, 2008. In conjunction with the issuance of the $125 million 2013 Notes, the Company recorded a premium of $1.4 million to be amortized over the remaining life of the notes utilizing the effective interest rate method. The remaining unamortized premium was $1.1 million at March 31, 2008.

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 extinguished substantially all of its 2011 Notes for a premium of $14.9 million plus accrued interest of $3.5 million. There were approximately $0.3 million of the notes which were not redeemed and are still outstanding as of March 31, 2008. In connection with the extinguishment of substantially all of the 2011 Notes, the Company requested and received from the noteholders consent to eliminate most significant debt covenants associated with the 2011 Notes.

Debt Issuance Costs

The Company capitalizes certain direct costs associated with the issuance of long-term debt. At March 31, 2008, the Company had approximately $11.9 million of net debt issuance costs being amortized over the lives of the respective debt.

5. ASSET RETIREMENT OBLIGATIONS

If a reasonable estimate of the fair value of an obligation to perform site reclamation, dismantle facilities or plug and abandon wells can be made, the Company records a liability (an asset retirement obligation or ARO) on the consolidated balance sheet and capitalizes the asset retirement cost in oil and natural gas properties in the period in which the retirement obligation is incurred. In general, the amount of an ARO and the costs capitalized will be equal to the estimated future cost to satisfy the abandonment obligation using current 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 three months ended March 31, 2008:


Liability for asset retirement obligation as of December 31, 2007	$	23,800
Liabilities settled and divested		(83	)
Additions		802
Acquisitions ⁽¹⁾		1,145
Accretion expense		283

Liability for asset retirement obligation as of March 31, 2008	$	25,947

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

6. COMMITMENTS, CONTINGENCIES AND LITIGATION

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.

Rig Commitments

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 March 31, 2008, the Company has 13 drilling rigs under contract for a total commitment over three years of $54.7 million.

7. DERIVATIVE ACTIVITIES

Periodically, the Company enters into derivative commodity instruments to hedge its exposure to price fluctuations on anticipated oil and natural gas production. Under collar arrangements, if the index price rises above the ceiling price, the Company pays the counterparty. If the index price falls below the floor price, the counterparty pays the Company. Under price swaps, the Company is required to make payments to, or receive payments from, the counterparties based upon the differential between a specified fixed price and a price related to those quoted on the New York Mercantile Exchange for each respective period. Under put options, the Company pays a fixed premium to lock in a specified floor price. If the index price falls below the floor price, the counterparty pays the Company net of the fixed premium. If the index price rises above floor price, the Company pays the fixed premium. 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 senior revolving credit facility) 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 statement of operations.

At March 31, 2008, the Company had a $0.3 million derivative asset, $0.1 million of which was classified as current, and a $159.1 million derivative liability, $119.3 million of which was classified as current. The Company recorded a net derivative loss of $142.7 million ($140.9 million unrealized loss, $5.2 million loss for cash paid on settled contracts and net of a $3.4 million gain associated with the Company’s adoptions of SFAS 157 as discussed in Note 1, “Financial Statement Presentation”) for the three months ended March 31, 2008. The Company recorded a net derivative loss of $58.9 million ($74.9 million unrealized loss net of $16.0 gain for cash received on settled contracts) for the three months ended March 31, 2007.

At March 31, 2008, the Company had 114 open positions summarized in the tables below: 84 natural gas price collar arrangements, 12 natural gas price swap arrangements, six natural gas put options, seven crude oil price swap arrangements, three crude oil collar arrangements and two interest rate swap arrangements.

At December 31, 2007, the Company had 60 open positions summarized in the tables below: 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 March 31, 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
April 2008 - December 2008	37,570,000	$	5.00 -$7.25	$	6.89	$	6.45 -$12.25	$	10.19
January 2009 - December 2009	62,030,000	$	7.00 -$8.25	$	7.30	$	9.60 -$12.70	$	10.68

At March 31, 2008, the Company had the following natural gas swap positions:


	Swaps
Period	Volume in Mmbtu’s	Price / Price Range		Weighted Average Price
April 2008 - December 2008	11,890,000	$	7.71 - $8.28	$	7.94
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 March 31, 2008, the Company had the following natural gas put options:


	Floors
Period	Volume in Mmbtu’s	Weighted Average Price
April 2008 - December 2008	5,480,000	$	7.00

The Company has recorded a deferred premium liability of $2.3 million of long-term debt which has been classified as current at March 31, 2008 based on a weighted average deferred premium of $0.41 per Mmbtu. The natural gas put option contracts contain deferred premiums that will be paid as the contracts expire.

Crude Oil

At March 31, 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
April 2008 - December 2008	595,000	$	34.00 -$70.00	$	64.97	$	45.30 -$85.05	$	80.26

At March 31, 2008, the Company had the following crude oil swap positions:


	Swaps
Period	Volume in Bbls	Price / Price Range		Weighted Average Price
April 2008 - December 2008	314,250	$	38.10 - $81.70	$	66.39
January 2009 - December 2009	273,750	$	76.85 - $77.30	$	77.00
January 2010 - December 2010	273,750	$	75.10 - $75.55	$	75.25

Interest

At March 31, 2008, the Company had the following interest rate swap positions:


	Swaps
Period	Notional Amount		Fixed Rate Range	Weighted Average Price
April 2008 - December 2010	$	200,000,000	2.39% - 2.8775%	2.634	%

8. STOCKHOLDERS’ EQUITY

On January 29, 2008, the Company entered into an underwriting agreement, pursuant to which the Company sold an aggregate of 18,000,000 shares of its common stock, $0.001 par value to the several underwriters named in the underwriting agreement. Pursuant to the underwriting agreement, the Company granted the underwriters a 30-day option to purchase up to an additional 2,700,000 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 and the sale of 20,700,000 shares of common stock closed on February 1, 2008. The net proceeds from the sale were approximately $297 million, after deducting underwriting discounts and commissions and estimated expenses.

Stock Appreciation Rights and Stock Options

Though not utilized until 2007, the 2004 Employee Plan and the KCS 2005 Plan permit awards of stock appreciation rights. A stock appreciation right is similar to a stock option, in that it represents the right to realize the increase in market price, if any, of a fixed number of shares over the grant value of the right, which is equal to the market price of the Company’s common stock on the date of grant. However, to realize the value of a stock option the holder must pay the exercise price in exchange for shares of stock underlying the option, the value embodied by the stock appreciation right, if any, are settled in exchange for shares of common stock valued on the date of settlement. Stock appreciation rights vest one-third annually after the original grant date. The term is ten years from the date of grant, after which the stock appreciation right expires.

During the three months ended March 31, 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 $18.08 with a weighted average price of $18.06. 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 March 31, 2008, the unrecognized compensation expense related to non-vested stock appreciation rights and stock options totaled $7.0 million and will be recognized on a straight line basis over the weighted average remaining vesting period of 1.5 years.

During the three months ended March 31, 2007, the Company granted a combination of stock appreciation rights and stock options covering 1.4 million shares of common stock to employees of the Company. The stock appreciation rights and stock options have exercise prices ranging from $12.74 to $16.04 with a weighted average price of $14.03. These stock appreciation rights and options vest over a three year period at a rate of one-third on the annual anniversary date of the grant and expire ten years from the grant date.

Restricted Stock

During the three months ended March 31, 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 $18.08 with a weighted average price of $18.05.

During the three months ended March 31, 2007, the Company granted 0.7 million shares of restricted stock to employees of the Company. These restricted shares were granted at prices ranging from $11.64 to $12.26 with a weighted average price of $11.64.

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 March 31, 2008, the unrecognized compensation expense related to non-vested restricted stock totaled $12.3 million and will be recognized on a straight line basis over the weighted average remaining vesting period of 1.5 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 $0.1 million in compensation cost for the three months ended March 31, 2008 and 2007. At March 31, 2008, the unrecognized compensation expense related to non-vested performance shares totaled $0.5 million.

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:


	Three Months Ended March 31,
	2008 ⁽¹⁾			2007
Weighted average value per option granted during the period⁽²⁾	$	5.28		$	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 March 31,
	2008			2007
	(In thousands, except per share amounts)
Basic
Net loss	$	(55,612	)	$	(19,415	)

Weighted average basic number of shares outstanding		183,629			167,306

Basic loss per share	$	(0.30	)	$	(0.12	)

Diluted
Net loss	$	(55,612	)	$	(19,415	)

Weighted average basic number of shares outstanding		183,629			167,306
Common stock equivalent shares representing shares issuable upon exercise of stock options and stock appreciation rights		Anti-dilutive			Anti-dilutive
Common stock equivalent shares representing shares issuable upon exercise of warrants		Anti-dilutive			Anti-dilutive
Common stock equivalent shares representing shares included upon vesting of restricted shares		Anti-dilutive			Anti-dilutive

Weighted average diluted number of shares outstanding		183,629			167,306

Diluted net loss per share	$	(0.30	)	$	(0.12	)

The following common stock equivalents were not included in the computation for diluted loss per share because their effects would be antidilutive:


	Three Months Ended March 31,
Common Stock Equivalents:	2008	2007
	(In thousands)
Options and stock appreciation rights	990	887
Warrants	—	18

	990	905

10. ADDITIONAL FINANCIAL STATEMENT INFORMATION

Certain balance sheet amounts are comprised of the following:


	March 31, 2008		December 31, 2007
	(In thousands)
Accounts receivable:
Oil and gas sales	$	100,463	$	77,033
Joint interest accounts		71,785		52,210
Other		2,045		18,895

	$	174,293	$	148,138

Prepayments and other:
Prepaid insurance	$	1,160	$	2,690
Prepaid drilling costs		16,396		13,937
Other		4,641		4,392

	$	22,197	$	21,019

Accounts payable and accrued liabilities:
Trade payables		24,867	$	25,751
Revenues and royalties payable		94,652		90,967
Accrued capital costs		114,981		117,748
Accrued interest expense		25,010		37,557
Other prepayment liabilities		13,634		10,977
Accrued lease operating expenses		5,871		6,373
Accrued ad valorem taxes payable		2,860		5,578
Accrued employee compensation		2,400		3,468
Other		20,950		33,052

	$	305,225	$	331,471

11. SUBSEQUENT EVENTS

Effective May 5, 2008, the Company entered into the Sixth Amendment (the 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. The Sixth Amendment included a waiver as of March 31, 2008 for existing commodity agreements involving in excess of 85% of projected production from proved, developed producing oil and gas properties, provided that the notional volumes for commodity swap agreements do not exceed 100% of the lesser of current production at the time the hedge is executed, or total internally forecasted production. In addition, hedges cannot exceed 75% and 50% of such amounts in 2011 and 2012, respectively. The Sixth Amendment also modified the covenant limiting our ability to incur certain debt to permit us to incur additional long-term debt in connection with our proposed equity and long-term debt offerings, discussed below, subject to a simultaneous reduction in our 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 we may issue.

On April 28, 2008, the Company collected $100 million related to its note receivable from the purchaser of its Gulf Coast properties. The note receivable had an original maturity date of five years and ninety-one days from the closing date and had an interest rate of 12% per annum payable in kind at the purchaser’s option. The purchaser had the right to redeem the note 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 150 days after November 30, 2007, accrued interest would be waived.

On May 6, 2008, the Company announced its intention to raise approximately $1 billion in capital through a combination of equity and long-term debt offerings. Proceeds from the offerings are intended to be used to pay down the outstanding borrowings under the senior revolving credit facility, which will provide the Company with additional financial flexibility to fund its increased capital budget of $1.3 billion for the year ended December 31, 2008 and potential acquisitions.

In the second quarter of 2008, the Company made the decision to withdraw its proposed Master Limited Partnership public offering and will expense the related costs of $3.3 million in interest and other expense.

Item 2.

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

The following discussion of operations for the three months ended March 31, 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, 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 focus on maintaining 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 continually seek opportunities to increase our drilling opportunities in our core areas, where we can apply our experience and economies of scale, including the Fayetteville Shale in Arkansas and in 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.

During the first quarter of 2008, we initiated leasing and acquisition efforts in order to supplement our existing Elm Grove/Caspiana field leasehold position of approximately 30,000 net acres that we believe is prospective for the Haynesville Shale. In the last several months, the Haynesville Shale has become one of the most active 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 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 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 have a total of approximately 30,000 net acres of Haynesville Shale rights that are held by shallower production in Elm Grove/Caspiana. In addition, we have leased or have the right to acquire approximately 108,000 additional net acres throughout the prospective area of the play. We are currently drilling our first horizontal well and expect to spud two additional horizontal wells during the second quarter of this year. We plan to drill a total of 10 wells in 2008 and anticipate increasing that activity significantly in 2009, subject to drilling results.

On May 6, 2008, we announced our intention to raise approximately $1 billion in capital through a combination of equity and long-term debt offerings. Proceeds from these offerings are intended to be used to pay down the outstanding borrowings under our senior revolving credit facility, which will provide us with additional financial flexibility to fund our recently increased 2008 capital budget of $1.3 billion for the year ended December 31, 2008 and potential acquisitions.

In the second quarter of 2008, we made the decision to withdraw our proposed Master Limited Partnership public offering and will expense the related costs of $3.3 million in interest or other expense.

In the first three months of 2008, we produced 23.7 billion cubic feet of natural gas equivalent (Bcfe) compared to production of 29.0 Bcfe for the comparable period of the prior year resulting in a decrease of 5.3 Bcfe primarily due to the sale of our Gulf Coast properties during the fourth quarter of 2007. Natural gas production was 21.5 billion cubic feet (Bcf) and oil production was 365 thousand barrels of oil (Mbbls) for the

first three months of 2008. Natural gas equivalent production decreased 5.3 Bcfe from the same period in 2007. This decrease was primarily attributable to the sale of our Gulf Coast properties during the fourth quarter of 2007. We drilled 130 gross wells (49.1 net) during the first three months of 2008, all of which were successful. We reported oil and gas revenues for the three months ended March 31, 2008 of $214.9 million. This represents an increase of $5.7 million as compared to the prior year as increasing oil and 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 three months ended March 31, 2008 and 2007 were from operating and financing activities. Proceeds from the sale of common stock 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 capital and exploration 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 have increased our 2008 capital budget from $800 million to $1.3 billion. As discussed above, on May 6, 2008, we announced our intent to raise approximately $1 billion in capital through the combination of equity and long-term debt offerings. We expect to use proceeds from these offerings to pay down the outstanding borrowings under our senior revolving credit facility, which will provide us with additional financial flexibility to fund our recently increased 2008 capital budget for the year ended December 31, 2008 and potential acquisitions. See “Results of Operations” below for a review of the impact of prices and volumes on sales.

Net increase in cash is summarized as follows:


	Three Months Ended March 31,
	2008			2007
	(In thousands)
Cash flows provided by operating activities	$	61,185		$	135,272
Cash flows used in investing activities		(323,312	)		(226,332	)
Cash flows provided by financing activities		267,514			91,411

Net increase in cash	$	5,387		$	351

Operating Activities. Net cash provided by operating activities for the three months ended March 31, 2008 and 2007 were $61.2 million and $135.3 million, respectively.

Net cash provided by operating activities decreased in 2008 primarily due to changes in working capital associated with the 18% decrease in production volumes as a result of the sale of our Gulf Coast properties during the fourth quarter of 2007 partially offset by the 25% 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 robust capital program of $1.3 billion in 2008 as well as recent acquisition activities. 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 $323.3 million and $226.3 million for the three months ended March 31, 2008 and 2007, respectively.

During the first three months of 2008, we spent $150.4 million on capital expenditures in conjunction with our drilling program. We participated in the drilling of 130 gross wells in 2008 (49.1 net wells), none of which were dry holes. We spent an additional $14.4 million on other property and equipment during the first three months of 2008 as well, primarily to fund the development of gathering systems in the Fayetteville Shale in Arkansas.

During the first three months of 2008, we spent $428.3 million primarily to acquire additional interests in the Fayetteville Shale in Arkansas, in both the Elm Grove and Terryville fields in Louisiana and in the Haynesville Shale in Louisiana which was partially funded by the remaining restricted cash that we had deposited with a qualified intermediary to facilitate like-kind exchange transactions. Our program to acquire additional interests and acreage in these key fields is ongoing.

During the first three months of 2007, we spent $224.5 million on capital expenditures in conjunction with our drilling program. We participated in the drilling of 81 gross wells, of which six were dry holes, for a success rate of 93%.

We recently increased our 2008 budget from $800 million to $1.3 billion. Our capital budget for 2008 is expected to be funded from cash flows from operations, additional borrowings under our senior revolving credit facility and funds attributable to expected proceeds from the equity and long-term debt offerings we announced on May 6, 2008. 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 $267.5 million and $91.4 million for the three months ended March 31, 2008 and 2007, respectively. Cash flows provided by financing activities in 2008 were the result of the sale of 20.7 million shares of common stock for approximately $297 million, primarily to fund our drilling and acquisition activities.

On January 29, 2008, we entered into an underwriting agreement, pursuant to which we sold an aggregate of 18,000,000 shares of our common stock, $0.001 par value to the several underwriters named in the underwriting agreement. Pursuant to the underwriting agreement, we granted the underwriters a 30-day option to purchase up to an additional 2,700,000 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 and the sale of 20,700,000 shares of common stock closed on February 1, 2008. The net proceeds from the sale were approximately $297 million, after deducting underwriting discounts and commissions and estimated expenses.

We seek to maintain excess availability under our senior revolving credit facility. Excess cash flow and non-core asset sales are used to repay debt to the extent available. During the first three months of 2008, we had net repayments of $35 million primarily due to the sale of common stock discussed above offset by the cash requirements of our drilling program as well as to fund our acquisition activities in 2008. As of March 31, 2008, our senior revolving credit facility had a $1 billion borrowing base and outstanding borrowings of approximately $535 million.

During the first three months of 2007, we had net borrowings of $87.6 million primarily due to the cash requirements of our drilling program.

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

In our Form 10-K 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 March 31, 2008, we had 13 drilling rigs under contract for a total commitment over three years of $54.7 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 March 31, 2008 and 2007

We reported a net loss of $55.6 million for the three months ended March 31, 2008 compared to a net loss of $19.4 million for the comparable period in 2007. The increase in our net loss of $36.2 million from the three months ended March 31, 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 $142.7 million in 2008.


In thousands (except per unit and per Mcfe amounts)	Three Months Ended March 31,						Change
In thousands (except per unit and per Mcfe amounts)	2008			2007			Change
Net loss	$	(55,612	)	$	(19,415	)	$	(36,197	)
Oil and gas sales		214,938			209,243			5,695
Expenses:
Production:
Lease operating		12,394			15,876			(3,482	)
Workover and other		537			2,177			(1,640	)
Taxes other than income		10,964			13,650			(2,686	)
Gathering, transportation and other		9,523			7,424			2,099
General and administrative:
General and administrative		13,556			12,713			843
Stock-based compensation		2,598			2,888			(290	)
Depletion, depreciation and amortization:
Depletion—Full cost		82,073			94,700			(12,627	)
Depreciation—Other		771			694			77
Accretion expense		283			444			(161	)
Net loss on derivative contracts		(142,741	)		(58,933	)		(83,808	)
Interest expense and other		(27,537	)		(30,750	)		3,213
Income tax benefit		32,427			11,591			20,836

Production:
Natural Gas—Mmcf⁽¹⁾		21,523			24,526			(3,003	)
Crude Oil—Mbbl		365			748			(383	)
Natural Gas Equivalent—Mmcfe		23,713			29,014			(5,301	)
Average Daily Production—Mmcfe		261			322			(61	)

*Average price per unit⁽²⁾***:
Gas price per Mcf⁽¹⁾	$	8.34		$	6.82		$	1.52
Oil price per Bbl		94.86			56.11			38.75
Equivalent per Mcfe		9.03			7.21			1.82

Average cost per Mcfe:
Production:
Lease operating		0.52			0.55			(0.03	)
Workover and other		0.02			0.08			(0.06	)
Taxes other than income		0.46			0.47			(0.01	)
Gathering, transportation and other		0.40			0.26			0.14
General and administrative:
General and administrative		0.57			0.44			0.13
Stock-based compensation		0.11			0.10			0.01
Depletion		3.46			3.26			0.20

(1)	Approximately 3% of natural gas production represents natural gas liquids (calculated with a 6:1 equivalent ratio) with an average price of $61.53 per Bbl and $32.47 per Bbl for the three months ended March 31, 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 March 31, 2008, oil and natural gas sales increased $5.7 million from the same period in 2007, to $214.9 million. The increase was primarily due to the increase of $1.82 per Mcfe in our realized average price to $9.03, which increased revenues by $43 million. The effect of the increase in price was partially offset by a decrease in production of 5,301 Mmcfe primarily due to the sale of our Gulf Coast properties during the fourth quarter of 2007. Decreased production led to a $37 million decrease in revenues for the three months ended March 31, 2008.

Lease operating expenses decreased $3.5 million for the three months ended March 31, 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 $0.55 per Mcfe in 2007 to $0.52 per Mcfe in 2008. This decrease on a per unit basis is primarily due to our continued cost control efforts to lower our lease operating expense. In addition, we continue to identify divestment prospects in outlying, higher operating cost properties.

Taxes other than income decreased $2.7 million for the three months ended March 31, 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 a percentage of gross oil and natural gas sales. As a percentage of oil and gas sales, taxes other than income decreased from 6.5% in 2007 to 5.1% in 2008. This decrease is primarily attributable to the timing of refunds received and reassessments that occurred as well as an increase in production associated with our recent acquisitions and drilling program in the Fayetteville Shale in Arkansas.

Gathering, transportation and other expense increased $2.1 million, or $0.14 per Mcfe, for the three months ended March 31, 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 transportation costs.

General and administrative expense for the three months ended March 31, 2008 increased $0.8 million as compared to the same period in 2007 to $13.6 million. 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 $0.44 per Mcfe in 2007 to $0.57 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.

Stock-based compensation decreased $0.3 million for the three months ended March 31, 2008 as compared to the same period in the prior year. This decrease was primarily due to the charge we took during the fourth quarter of 2007 associated with the early vesting for employees impacted by the sale of our Gulf Coast properties. This decrease was partially offset by additional stock options, stock appreciation rights and restricted stock grants to employees during 2008.

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 $12.6 million for the three months ended March 31, 2008 from the same period in 2007, to $82.1 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 $0.20 per Mcfe to $3.46 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 as well as an increase in our future development costs.

We enter into derivative commodity instruments to hedge our exposure to price fluctuations on our anticipated oil and natural gas production. Consistent with the prior year, we have elected not to designate any positions as cash flow hedges for accounting purposes, and accordingly, we recorded the net change in the mark-to-market value of these derivative contracts in the consolidated statement of operations. At March 31, 2008, we had a $0.3 million derivative asset, $0.1 million of which was classified as current, and a $159.1

million derivative liability, $119.3 million of which was classified as current. The Company recorded a net derivative loss of $142.7 million ($140.9 million unrealized loss, $5.2 million loss for cash paid on settled contracts and net of a $3.4 million gain associated with the adoption of SFAS 157) for the three months ended March 31, 2008 compared to a net derivative loss of $58.9 million ($74.9 million unrealized loss net of a $16.0 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 decreased $3.2 million for the three months ended March 31, 2008 compared to the same period in 2007. This decrease was primarily due to the $2.9 million amortization of the discount recorded on the note receivable we received in connection with the sale of our Gulf Coast properties during the fourth quarter of 2007. The increase in our average debt balance for the first quarter of 2008 as compared to the same period in 2007 was offset by a decrease in interest rates in 2008.

Income tax benefit for the three months ended March 31, 2008 increased $20.8 million from the prior year. The increase in income tax benefit from prior year was primarily due to our pre-tax loss of $88.0 million for the three months ended March 31, 2008 compared to pre-tax loss of $31.0 million in 2007. The effective tax rates for the three months ended March 31, 2008 and 2007 were 36.8% and 37.4%, respectively. The decrease 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 and offset by a one-time discrete expense item.

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.

We are also exposed to interest rate risk on our variable rate debt. 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 are exposed to market risk on our 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. Please refer to Item 1. Condensed Consolidated Financial Statements—Note 7, “Derivative Activities” for additional information.

Interest Sensitivity

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

At March 31, 2008, total debt excluding related discounts and premiums was $1.6 billion, of which approximately 66%, or $1.0 billion, bears interest at a weighted average fixed interest rate of 8.6% per year. The remaining 34% of our total debt balance at March 31, 2008, or $535 million, bears interest at floating or market interest rates that at our option are tied to the prime interest rate or LIBOR. Fluctuations in market interest rates will cause our annual interest costs to fluctuate. During the first quarter of 2008, we made the decision to mitigate a portion of our 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 our senior revolving credit facility to a fixed rate obligation, thereby reducing our exposure to market rate fluctuations.

At March 31, 2008, the weighted average interest rate on our variable rate debt was 4.5% per year. If the balance of our variable interest rate debt at March 31, 2008 were to remain constant, a 10% change in market interest rates would impact our cash flow by approximately $0.4 million per quarter, including the impact of our interest rate swaps.

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 March 31, 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.

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds

None.

Item 3.

Defaults Upon Senior Securities

None.

Item 4.

Submission of Matters to a Vote of Security Holders

None.

Item 5.

Other Information

None.

Item 6.

Exhibits

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


Exhibit No		Description

3.1		Certificate of Incorporation for Petrohawk Energy Corporation (Incorporated by reference to Exhibit 3.1 to our Form S-8 filed on July 29, 2004).

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

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

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

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

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

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

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

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

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

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


Exhibit No		Description

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).

10.1		Fifth 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 10.1 to our Current Report on Form 8-K filed February 7, 2008).

10.2*		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

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: May 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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Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents