Table of Contents

Index to Financial Statements

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF

THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2007

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 is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  x    No  ¨

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes  ¨    No  x

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 and (2) has been subject to such filing requirements for the past 90 days.    Yes  x    No  ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See the definition 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 Act).    Yes  ¨    No  x

The aggregate market value of common stock, par value $.001 per share, held by non-affiliates (based upon the closing sales price on the New York Stock Exchange on June 29, 2007), the last business day of registrant’s most recently completed second fiscal quarter was approximately $2.6 billion.

As of February 21, 2008, there were 192,083,466 shares of common stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Information required by Part III, Items 10, 11, 12, 13 and 14, is incorporated by reference to portions of the registrant’s definitive proxy statement for its 2008 annual meeting of stockholders which will be filed on or before April 30, 2008.

 

 

 

---

Table of Contents

Index to Financial Statements

TABLE OF CONTENTS

 

				PAGE
PART I
ITEM 1.		Business		4
ITEM 1A.		Risk factors		14
ITEM 1B.		Unresolved staff comments		22
ITEM 2.		Properties		22
ITEM 3.		Legal proceedings		22
ITEM 4.		Submission of matters to a vote of security holders		22
PART II
ITEM 5.		Market for registrant’s common equity, related stockholder matters and issuer purchases of equity securities		23
ITEM 6.		Selected financial data		25
ITEM 7.		Management’s discussion and analysis of financial condition and results of operations		26
ITEM 7A.		Quantitative and qualitative disclosures about market risk		42
ITEM 8.		Consolidated financial statements and supplementary data		43
ITEM 9.		Changes in and disagreements with accountants on accounting and financial disclosure		83
ITEM 9A.		Controls and procedures		83
ITEM 9B.		Other information		84
PART III
ITEM 10.		Directors, executive officers and corporate governance		85
ITEM 11.		Executive compensation		85
ITEM 12.		Security ownership of certain beneficial owners and management and related stockholder matters		85
ITEM 13.		Certain relationships and related transactions, and director independence		85
ITEM 14.		Principal accountant fees and services		85
PART IV
ITEM 15.		Exhibits and financial statement schedules		86

 

2

---

Table of Contents

Index to Financial Statements

Special note regarding forward-looking statements

This report on Form 10-K 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 which describe factors that could cause our actual results to differ from those set forth in the forward-looking statements, including the following factors:

 

•

the volatility in commodity prices for oil and natural gas;

 

•

the ability to replace oil and natural gas reserves;

 

•

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

 

•

our ability to successfully develop our large inventory of undeveloped acreage held in resource-style areas in Arkansas and Louisiana;

 

•

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

 

•

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

 

•

drilling and operating risks and expense cost escalations;

 

•

exploration and development risks;

 

•

competition including competition for acreage in resource-style areas;

 

•

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

 

•

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;

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.

 

3

---

Table of Contents

Index to Financial Statements

PART I

 

ITEM 1.

BUSINESS

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.

At December 31, 2007, our estimated total proved oil and natural gas reserves were approximately 1,062 billion cubic feet of natural gas equivalent (Bcfe), consisting of 18 million barrels of oil (MMBbls), and 955 billion cubic feet (Bcf) of natural gas and natural gas liquids. Approximately 57% of our proved reserves were classified as proved developed. We maintain operational control of approximately 77% of our proved reserves.

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. As discussed below, we believe the steps we have taken during 2007 will help us grow production and reserves in resource-style, tight-gas areas in North Louisiana and Arkansas. Our current drilling inventory consists of approximately 10,500 identified locations, 9,000 of which are resource-style.

Recent Developments

Effective February 5, 2008, we entered into the Fifth Amendment (the Fifth Amendment) to Second Amended and Restated Senior Revolving Credit Agreement dated as of July 12, 2006 among us, each of the lenders from time to time party thereto (the Lenders), BNP Paribas, as administrative agent for the Lenders, Bank of America, N.A. and BMO Capital Markets Financing, Inc., as co-syndication agents for the Lenders, and JPMorgan Chase Bank, N.A, Wells Fargo Bank, N.A and Fortis Capital Corp., as co-documentation agents for the Lenders. Pursuant to the Fifth Amendment, our borrowing base under the senior revolving credit facility was increased from $675 million to $1 billion, inclusive of a $100 million component set to expire effective February 5, 2009.

On January 29, 2008, we entered into an underwriting agreement (the Underwriting Agreement), pursuant to which we sold an aggregate of 18,000,000 shares of our common stock, $0.001 par value (the Common Stock) to the several underwriters named in the Underwriting Agreement (the Underwriters). 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 which was exercised by the Underwriters. These transactions closed on February 1, 2008. The net proceeds from the sale of the Common Stock sold (including Common Shares sold pursuant to the Underwriters’ over-allotment option) were approximately $297.3 million (after deducting underwriting discounts and commissions and estimated expenses).

In June 2007, we announced our intention to form a publicly-traded master limited partnership, (HK Energy Partners LP, or the MLP), which would initially acquire certain of our oil and natural gas properties located in West Texas, New Mexico and Oklahoma. On October 30, 2007, we filed a Form S-1 with the Securities and Exchange Commission to form this MLP. At the closing of the initial public offering, we would be the general partner of the MLP and hold a majority ownership in the units of the MLP. We would continue to operate and own a working interest in certain of the assets that would form the MLP. On January 25, 2008, due to current market conditions, we announced that we have delayed the proposed MLP public offering.

 

4

---

Table of Contents

Index to Financial Statements

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

On January 7, 2008, we entered into an agreement to purchase additional properties located in the Fayetteville Shale for $231.3 million after customary closing adjustments. These properties include interests primarily in Van Buren and Cleburne Counties, Arkansas. These properties include approximately 18,500 net acres and are substantially undeveloped. The transaction closed on February 8, 2008.

We have recently completed the following transactions:

Fayetteville Shale

During the last six months of 2007, we increased our position in the Fayetteville Shale by acquiring approximately 90,000 net acres that we believe to be strategically located, the vast majority of which represent undeveloped properties. These acquisitions were completed in three separate transactions which closed in July, August and December for total cash consideration of approximately $409 million. In addition, we added approximately 20,000 net acres in the Fayetteville Shale, for approximately $20 million through our ongoing leasing activities.

Gulf Coast Properties

In June 2007, we announced a strategic repositioning involving plans to sell our Gulf Coast properties and concentrate our efforts on developing and expanding our resource-style assets, including tight-gas properties in North Louisiana and the Fayetteville Shale in central Arkansas.

On November 30, 2007, we closed the sale of our Gulf Coast properties for $825 million, consisting of $700 million in cash and a $125 million note from the purchaser (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 within one year of the issuance of the Note for $100 million plus accrued and unpaid interest. If the redemption occurs within 150 days of the issuance of the Note, 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 our full cost pool.

Business Strategy

Our primary objective is to increase stockholder value through the combination of attractive acquisitions and continued development of existing proved properties, complimented by potentially significant exploration projects. Our strategy emphasizes:

 

•

Natural gas reserves in concentrated areas—During 2007, we completed the sale of our Gulf Coast properties, which we feel will allow us to concentrate our efforts on developing and expanding our significant base of Mid-continent natural gas resource-style activities, including tight-gas development in North Louisiana and the Fayetteville Shale in central Arkansas. We expect to continue to add to our interests and acreage positions in these key areas.

 

•

Attractive undeveloped reserves—We have a significant inventory of future drilling locations in our core areas. Generally, these locations range in depth from 5,000 feet to 13,000 feet and we believe offer relatively low risk opportunities to add production and proved reserves. Most of the locations are step-out or extension wells from existing production in resource plays. We also seek to add proved reserves and increase production through the use of advanced technologies, including detailed reservoir engineering analysis, drilling infill and extension wells utilizing sophisticated fracture stimulation techniques and selectively recompleting existing wells. We believe that many of our properties have significant potential and in certain cases have not been actively developed in the past.

 

5

---

Table of Contents

Index to Financial Statements

•

Focus on operations—We focus on reducing the per unit operating costs associated with our existing properties as evidenced by our lease operating expense reduction from $0.73 per Mcfe in 2006 to $0.56 per Mcfe in 2007.

 

•

Divestment of non-core properties—We continually evaluate our property base to identify opportunities to divest non-core, higher cost or less productive properties with limited development potential. This strategy allows us to focus on a portfolio of core properties with significant potential to increase our proved reserves and production.

 

•

Monetize at an appropriate time with the goal of providing superior returns to stockholders—The independent exploration and production industry has been consolidating for a number of years. Our business strategy embraces this trend. We intend to continue to assemble a portfolio of quality proved reserves and drilling opportunities within a core group of operated properties that may potentially be desirable as a strategic acquisition target by larger industry participants.

Oil and Natural Gas Reserves

The December 31, 2007 proved reserve estimates presented in this document were prepared by Netherland, Sewell and Associates, Inc. (Netherland, Sewell). For additional information regarding estimates of proved reserves, the preparation of such estimates by Netherland, Sewell and other information about our oil and natural gas reserves, see Item 8. Consolidated Financial Statements and Supplementary Data—“Supplemental Oil and Gas Information.” Our reserves are sensitive to commodity prices and their effect on economic producing rates.

The reserves information in this Form 10-K represents only estimates. There are a number of uncertainties inherent in estimating quantities of proved reserves, including many factors beyond our control, such as commodity pricing. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates of different engineers may vary. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revising the original estimate. Accordingly, initial reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. The meaningfulness of such estimates depends primarily on the accuracy of the assumptions upon which they were based. Except to the extent we acquire additional properties containing proved reserves or conduct successful exploration and development activities or both, our proved reserves will decline as reserves are produced.

The following table presents certain information as of December 31, 2007. Oil and natural gas liquids are based on the December 31, 2007 West Texas Intermediate posted price of $92.50 per barrel (Bbl) and are adjusted by lease for quality, transportation fees, and regional price differentials. Natural gas prices are based on a December 31, 2007 Henry Hub spot market price of $6.80 per million British thermal unit (MMbtu), as adjusted by lease for energy content, transportation fees, and regional price differentials. All prices were held constant in accordance with the United States Securities and Exchange Commission (SEC) guidelines. Shut-in wells currently not capable of production are excluded from producing well information.

 

		Mid-Continent Region		Western Region		Total
Proved Reserves at Year End (Bcfe)
Developed		377.5		229.2		606.7
Undeveloped		359.6		95.3		454.9
Total		737.1		324.5		1,061.6
Gross Wells		1,173		3,625		4,798
Net Wells (1)		532.1		1,087.0		1,619.1

 

(1)	Net wells represents our working interest share of each well. The term net as used in “net production” throughout this document refers to amounts that include only acreage or production that we own and produce to our interest, less royalties and production due to others.

 

6

---

Table of Contents

Index to Financial Statements

Core Operating Regions

Mid-Continent Region

In the Mid-Continent region, we concentrate our drilling program primarily in North Louisiana and in the Fayetteville Shale in the Arkoma Basin. We believe our Mid-Continent region operations provide us with a solid base for future production and reserve growth. During 2007, we drilled 267 wells in this region with a success rate of 98%. In 2008, we plan to drill 635 wells in this region, the majority of which will be operated by us. In 2007, we produced 53 Bcfe in this region, or 146 million cubic feet of natural gas equivalent per day (MMcfe/d). As of December 31, 2007, approximately 69% of our proved reserves, or 737 Bcfe, were located in our Mid-Continent fields.

 

•

Elm Grove and Caspiana Field—Our largest field area, located primarily in Bossier and Caddo Parishes of North Louisiana, produces from the Hosston and Cotton Valley formations. These zones are composed of low permeability sandstones that require fracture stimulation treatments to produce. We currently own interests in 123 sections with over 30,500 net acres. We own varying working and net revenue interests in this field. We produced 34 Bcfe in 2007 in this field. As of December 31, 2007, proved reserves for the Elm Grove / Caspiana field were approximately 542 Bcfe, of which approximately 50% were classified as proved undeveloped and approximately 19% proved developed non-producing.

We have been actively drilling infill wells on 40-acre and 20-acre spacing at Elm Grove utilizing between four and six operated drilling rigs. During 2007, we drilled 125 wells, all of which were successful. In 2008, we plan to drill 190 wells, including 20 horizontal wells that we expect to continue growing production and reserves. Additionally, we have successfully utilized coiled tubing for recompletions to fracture stimulate and commingle the shallower Hosston formation with the existing Lower Cotton Valley formation, increasing the present value of the wells and reducing additional capital expenditures. To date, we have performed over 150 of these procedures and have 53 planned in 2008. We recently completed a horizontal well with a production rate of 16.5 MMcfe/d. It was the first operated horizontal well that has been drilled in the Lower Cotton Valley Taylor sand. Based on these results, we have identified and scheduled a 10 well, two rig program targeting the Taylor sand in 2008.

Our recently closed acquisition in Elm Grove provides a new area of operation which we believe is significantly underdeveloped. The acreage has a large number of remaining 40-acre locations and has not had any 20-acre locations drilled to date. Additionally, the majority of the well bores have not been re-completed in the Hosston formation, which we believe will add significantly to our inventory of coiled tubing recompletions.

 

•

Terryville Field—Located in Lincoln Parish, Louisiana, this is our second largest producing field. We have acquired a significant acreage position and hold interests in over 100 sections with over 34,000 net acres. The objective formations in this field include the Cotton Valley, Bossier and Gray sands. We own varying working and net revenue interests in this field. As of December 31, 2007, proved reserves for this field were approximately 122 Bcfe. In 2007, we drilled 43 wells, all of which were successful. In 2008, we intend to drill 75 wells, including several extension and exploration wells. During 2007, we began a 20-acre downspacing program, drilling three wells. Based on the success to date of this initiative, we have 15 20-acre wells planned in 2008. We produced 14 Bcfe in 2007 in this field.

During 2007 we acquired a 50 square mile 3-D seismic dataset over the field. Delivered late in the third quarter, the data identified several areas which we believe present significant drilling opportunities. Specifically, the data has been used to identify potential gas bearing Gray sand structures, and an area of Bossier expansion that we feel is indicative sand development. During the later part of 2007 we drilled a number of wells in this area of Bossier expansion and have verified that the area does contain Bossier sands that have resulted in excellent production.

In late December 2007, we closed the acquisition of approximately 8,000 net acres immediately west and contiguous to our Terryville leasehold. The area overlies a large untested structure in the Gray sand

 

7

---

Table of Contents

Index to Financial Statements

and Lower Cotton Valley sands. The majority of the production from the field has come from Upper Cotton Valley and Hosston sands. However, these sands appear to be underdeveloped, and we have identified numerous developmental drilling opportunities. We have initiated steps to acquire approximately 60-square miles of 3-D seismic data over the acreage that will be merged with our existing 3D seismic data over Terryville.

 

•

Fayetteville Shale—We have assembled a position of approximately 150,000 net acres (including net acres from acquisitions discussed above), which we believe holds significant potential for production and reserve growth. The Fayetteville Shale is an unconventional gas reservoir located in the Arkoma Basin in Arkansas, at a depth of approximately 1,500 feet to 6,500 feet and ranging in thickness from 100 to 500 feet. The formation is a Mississippian-age shale that has similar geologic characteristics to the Barnett Shale in the Ft. Worth Basin of North Texas. Drilling in the play began in 2004 and has accelerated rapidly during the past two years, with over 400 wells drilled during 2007. To date, the best results have been obtained by drilling horizontal wells with lateral lengths of 2,500 feet to 3,000 feet and utilizing slickwater fracture stimulation completions. Due to the high degree of industry drilling success to date across portions of five counties, acquisition of acreage in the play has become extremely competitive. We own varying working and net revenue interests in this field. As of December 31, 2007, proved reserves for this field were approximately 54 Bcfe. During 2007, we drilled 70 wells and in 2008, we plan to drill 270 wells in this area, including 150 wells operated by us. We produced 3 Bcfe in 2007 in this area. We have taken steps to build gathering systems to ensure that we have adequate pipeline capacity to support our expanded activities in this area.

Western Region

Our principal properties in the Western Region include the Sawyer Field in Sutton County, Texas, Waddell Ranch Field in Crane County, Texas, WEHLU Field in Oklahoma County, Oklahoma, East Texas area concentrated in Panola, Harrison, Shelby and Nacadoches Counties, Texas, Jalmat Field in Lea County, New Mexico and TXL Field in Ector County, Texas. During 2007, we drilled 75 wells in this region with a success rate of 99%. In 2008, we plan to drill 35 operated and 90 non-operated wells in this region for a total of 125 gross wells. In 2007, we produced 28 Bcfe from this region, or 76 MMcfe/d. As of December 31, 2007, approximately 31% of our proved reserves, or 325 Bcfe, were located in our Western Region fields.

 

•

Waddell Ranch Field—This field is located in Crane County, Texas. The Waddell Ranch Field complex is comprised of over 76,900 gross or 17,000 net acres and is productive from over 15 different reservoirs. The primary production is from the Queen, Grayburg, San Andres, Clearfork, and Ellenburger formations ranging in depth from 3,000 feet to 11,000 feet. We have a working interest in this non-operated field that ranges from 19% to 75% that is burdened by a significant net profits interest that reduces our average working interest and our average net revenue interest to 13%. As of December 31, 2007, proved reserves for this field were approximately 56 Bcfe. In 2007, 12 wells were drilled along with 23 workovers. We produced 3 Bcfe in 2007 in this field. In 2008, we plan to drill 10 wells and complete 51 workovers.

 

•

Sawyer Canyon Field—This field is located in Sutton County, Texas. Our ownership in the field is comprised of interest in approximately 50 sections, and during the past several years we have been developing gas bearing Canyon sandstone formations ranging in depths from 5,500 feet to 6,800 feet. We have a 92% to 100% working interest in most of the areas we are actively drilling. As of December 31, 2007, proved reserves for this field were approximately 63 Bcfe. Six wells were drilled along with five workovers in 2007. We produced 4 Bcfe in 2007 in this field. In 2008, we plan to drill 24 wells.

 

•

WEHLU Field—The West Edmond Hunton Lime Unit, or WEHLU, covers 30,000 gross or 29,000 net acres primarily in Oklahoma County, Oklahoma. The WEHLU field, originally discovered in 1942, is the largest Hunton Lime formation field in the state of Oklahoma. The field has 38 oil and natural gas wells (36 currently producing approximately 6 MMcfe/d net) with stable production holding the entire

 

8

---

Table of Contents

Index to Financial Statements

unit. We own a 98% working interest and 80% net revenue interest in the majority of the field. Additionally, we have an agreement with a public company to jointly develop additional reserves and production in a portion of WEHLU. The area of mutual interest created by the agreement covers 5,680 acres located in the central northwest portion of the field and we own a 40% working interest and 33% net revenue interest in this area. As of December 31, 2007, proved reserves for this field were approximately 19 Bcfe. Three successful horizontal wells were drilled in 2007. We produced 3 Bcfe in 2007 in this field.

 

•

East Texas Area—Our properties in the East Texas Basin produce primarily from the Cotton Valley, Travis Peak and James Lime formations, which range in depth from approximately 6,500 feet to 10,000 feet. We own significant interests in the Joaquin, South Carthage, North Beckville and Blocker fields in Shelby, Panola and Harrison Counties, Texas. Our working interest in these fields is between 47% and 100%. We have been actively acquiring acreage in the developing James Lime horizontal play and in the Travis Peak vertical play in Nacogdoches and Shelby Counties, Texas. To date we have acquired over 25,000 net acres in the trend with an average working interest of 74%. As of December 31, 2007, proved reserves for this area were approximately 22 Bcfe. During 2007 we drilled three horizontal James Lime wells and four vertical Travis Peak wells in this trend, all successful. We produced 4 Bcfe in 2007 in this area. For 2008, 17 new wells are expected to be drilled.

 

•

TXL Field—This waterflood is located in Ector County, Texas and is unitized in the Clearfork/Tubb formation at approximately 5,600 feet. We have a 20% working interest and a 25% net revenue interest in this non-operated property. Over 100 additional infill drill sites remain to be drilled in this property which we believe will lead to additional proved reserves as well as upside potential. As of December 31, 2007, proved reserves for this field were approximately 25 Bcfe. No new wells were drilled in 2007, as the operator focused on infrastructure upgrades and rehabilitation work. We produced 1 Bcfe in 2007 in this field. For 2008, eight new wells are planned along with a number of pattern enhancement projects.

 

•

Jalmat Field—An extensive review of Jalmat Field, located in Lea County, New Mexico, has resulted in the identification of over 45 recompletion/stimulation workovers in the Tansill, Yates and Seven Rivers and significant waterflood potential in the Seven Rivers-Queen zone. We own a 96% working interest and 79% net revenue interest in this field. As of December 31, 2007, proved reserves for this field were approximately 49 Bcfe. There were no wells drilled in Jalmat during 2007. The 2007 capital program included a nine well recompletion/fracture stimulation program. We produced 2 Bcfe in 2007 in this field.

Risk Management

We use hedges to reduce price volatility, help ensure that we have adequate cash flow to fund our capital programs and manage price risks and returns on some of our acquisitions and drilling programs. Our decision on the quantity and price at which we choose to hedge our production is based in part on our view of current and future market conditions. While there are many different types of derivatives available, we primarily use oil and natural gas price collars, swap agreements and put options to attempt to manage price risk more effectively. The collar agreements are put and call options used to establish floor and ceiling commodity prices for a fixed volume of production during a certain time period. They provide for payments to counterparties if the index price exceeds the ceiling and payments from the counterparties if the index price is below the floor. The price swaps call for payments to, or receipts from, counterparties based on whether the market price of oil and natural gas for the period is greater or less than the fixed price established for that period when the swap is put in place. Under put options, we pay a fixed premium to lock in a specified floor price. If the index price falls below the floor price, the counterparty pays us net of the fixed premium. If the index price rises above floor price, we pay the fixed premium.

We only enter into derivatives arrangements with credit worthy counterparties as these arrangements expose us to the risk of financial loss if our counterparty is unable to satisfy its obligations. We will continue to evaluate

 

9

---

Table of Contents

Index to Financial Statements

the benefit of employing derivatives in the future. See Item 7A. Quantitative and Qualitative Disclosures about Market Risk for additional information.

Oil and Natural Gas Operations

Our principal properties consist of developed and undeveloped oil and natural gas leases and the reserves associated with these leases. Generally, developed oil and natural gas leases remain in force as long as production is maintained. Undeveloped oil and natural gas leaseholds are generally for a primary term of three to five years. In most cases, the term of our undeveloped leases can be extended by paying delay rentals or by producing reserves that are discovered under those leases.

The table below sets forth the results of our drilling activities for the periods indicated:

 

		Years Ended December 31,
		2007				2006				2005
		Gross		Net		Gross		Net		Gross		Net
Exploratory Wells:
Productive (1)		292		127.4		178		71.2		8		2.4
Dry		12		5.6		19		6.0		5		1.3
Total Exploratory		304		133.0		197		77.2		13		3.7
Development Wells:
Productive (1)		113		72.2		132		59.8		129		27.4
Dry		3		1.3		1		—		4		1.4
Total Development		116		73.5		133		59.8		133		28.8
Total Wells:
Productive (1)		405		199.6		310		131		137		29.8
Dry		15		6.9		20		6.0		9		2.7
Total		420		206.5		330		137.0		146		32.5

 

(1)	Although a well may be classified as productive upon completion, future production may deem the well to be uneconomical, particularly exploratory wells where there is no production history.

We own interests in developed and undeveloped oil and natural gas acreage in the locations set forth in the table below. These ownership interests generally take the form of working interests in oil and natural gas leases or licenses that have varying terms. The following table presents a summary of our acreage interests as of December 31, 2007:

 

		Developed Acreage				Undeveloped Acreage				Total Acreage
		Gross		Net		Gross		Net		Gross		Net
State
Alabama		—		—		27,389		13,695		27,389		13,695
Arkansas		17,211		5,242		209,423		160,063		226,634		165,305
Indiana		—		—		16,013		9,928		16,013		9,928
Kansas		9,791		6,491		9,677		4,016		19,468		10,507
Louisiana		118,644		60,648		51,878		46,766		170,522		107,414
New Mexico		20,830		11,814		560		389		21,390		12,203
Oklahoma		253,029		91,514		42,246		12,899		295,275		104,413
Texas		237,332		51,708		47,303		29,401		284,635		81,109
Total Acreage		656,837		227,417		404,489		277,157		1,061,326		504,574

 

10

---

Table of Contents

Index to Financial Statements

At December 31, 2007, we had estimated proved reserves of approximately 1,062 Bcfe comprised of 955 Bcf of natural gas and natural gas liquids and 18 MMBbls of oil. The following table sets forth, at December 31, 2007, these reserves:

 

		Proved Developed		Proved Undeveloped		Total Proved
Gas (Bcf) (1)		533.9		421.3		955.2
Oil (MMBbls)		12.1		5.6		17.7
Equivalent (Bcfe)		606.7		454.9		1,061.6

 

(1)	Amounts include natural gas liquids (calculated with a 6:1 equivalent ratio).

The estimates of quantities of proved reserves above were made in accordance with the definitions contained in SEC Regulation S-X, Rule 4-10(a). For additional information on our oil and natural gas reserves, see Item 8. Consolidated Financial Statements and Supplementary Data—“Supplementary Oil and Gas Information”.

We account for our oil and natural gas producing activities using the full cost method of accounting in accordance with SEC regulations. Accordingly, all costs incurred in the acquisition, exploration, and development of proved oil and natural gas properties, including the costs of abandoned properties, dry holes, geophysical costs, and annual lease rentals are capitalized. All general and administrative corporate costs unrelated to drilling activities are expensed as incurred. Sales or other dispositions of oil and natural gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless the ratio of cost to proved reserves would significantly change. Depletion of evaluated oil and natural gas properties is computed on the units of production method based on proved reserves. The net capitalized costs of evaluated oil and natural gas properties are subject to a quarterly full cost ceiling test.

Capitalized costs of our evaluated and unevaluated properties at December 31, 2007, 2006 and 2005 are summarized as follows:

 

		December 31,
		2007				2006				2005
		(in thousands)
Capitalized costs:
Evaluated properties		$	3,247,304			$	2,901,649			$	1,096,810
Unevaluated properties			677,565				537,611				162,133
			3,924,869				3,439,260				1,258,943
Less accumulated depreciation and depletion			(769,197	)			(379,017	)			(121,456	)
		$	3,155,672			$	3,060,243			$	1,137,487

Our oil and natural gas production volumes and average sales price are as follows:

 

		Years Ended December 31,
		2007			2006			2005
Production:
Gas production (MMcf) (1)			99,506			63,643			20,219
Oil production (MBbl)			2,816			2,703			1,555
Equivalent production (MMcfe)			116,402			79,863			29,549
Average Daily Production (MMcfe)			319			219			81
Average price per unit: (2)
Gas (per Mcf) (1)		$	6.92		$	6.57		$	8.46
Oil (per Bbl)			68.84			62.27			55.62
Equivalent (per Mcfe)			7.58			7.34			8.73

 

(1)	Approximately 4%, 5% and 7% of natural gas production represents natural gas liquids (calculated with a 6:1 equivalent ratio) with an average price of $43.70 per Bbl, $36.88 per Bbl and $40.50 per Bbl for the years ended December 31, 2007, 2006 and 2005, respectively.

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

 

11

---

Table of Contents

Index to Financial Statements

The 2007, 2006 and 2005 average oil and natural gas sales prices above do not reflect the impact of cash paid on, or cash received from, settled derivative contracts as these amounts are reflected as other income and expenses in the consolidated statement of operations, consistent with our decision not to elect hedge accounting. Including this impact 2007, 2006 and 2005 average gas sales prices were $7.41, $6.75 and $7.32 per thousand cubic feet (Mcf) and our average oil sales prices were $67.03, $54.28 and $47.20 per Bbl, respectively.

Competitive Conditions in the Business

The oil and natural gas industry is highly competitive and we compete with a substantial number of other companies that have greater financial and other resources. Many of these companies explore for, produce and market oil and natural gas, as well as carry on refining operations and market the resultant products on a worldwide basis. The primary areas in which we encounter substantial competition are in locating and acquiring desirable leasehold acreage for our drilling and development operations, locating and acquiring attractive producing oil and natural gas properties, obtaining sufficient rig availability, obtaining purchasers and transporters of the oil and natural gas we produce and hiring and retaining key employees. There is also competition between oil and natural gas producers and other industries producing energy and fuel. Furthermore, competitive conditions may be substantially affected by various forms of energy legislation and/or regulation considered from time to time by the government of the United States. It is not possible to predict the nature of any such legislation or regulation which may ultimately be adopted or its effects upon our future operations. Such laws and regulations may substantially increase the costs of exploring for, developing or producing oil and natural gas and may prevent or delay the commencement or continuation of a given operation.

Other Business Matters

Markets and Major Customers

In 2007 and 2005, we had one individual purchaser of our production that accounted for 10% and 12%, respectively, of our total sales. In 2006, we had no individual purchasers that accounted for more than 10% of our total sales. We do not believe the loss of any one of our purchasers would materially affect our ability to sell the oil and natural gas we produce. We believe other purchasers are available in our areas of operations.

Seasonality of Business

Weather conditions affect the demand for, and prices of, natural gas and can also delay drilling activities, disrupting our overall business plans. Demand for natural gas is typically higher in the fourth and first quarters resulting in higher natural gas prices. Due to these seasonal fluctuations, results of operations for individual quarterly periods may not be indicative of the results that may be realized on an annual basis.

Operational Risks

Oil and natural gas exploration and development involves a high degree of risk, which even a combination of experience, knowledge and careful evaluation may not be able to overcome. There is no assurance that we will discover or acquire additional oil and natural gas in commercial quantities. Oil and natural gas operations also involve the risk that well fires, blowouts, equipment failure, human error and other circumstances may cause accidental leakage of toxic or hazardous materials, such as petroleum liquids or drilling fluids into the environment, or cause significant injury to persons or property. In such event, substantial liabilities to third parties or governmental entities may be incurred, the satisfaction of which could substantially reduce available cash and possibly result in loss of oil and natural gas properties. Such hazards may also cause damage to or destruction of wells, producing formations, production facilities and pipeline or other processing facilities.

 

12

---

Table of Contents

Index to Financial Statements

As is common in the oil and natural gas industry, we will not insure fully against all risks associated with our business either because such insurance is not available or because we believe the premium costs are prohibitive. A loss not fully covered by insurance could have a materially adverse effect on our financial position and results of operations. For further discussion on risks see Item 1A. Risk Factors.

Regulations

Domestic exploration for, production and sale of, oil and natural gas are extensively regulated at both the federal, state and local levels. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue, and have issued, rules and regulations binding on the oil and natural gas industry that often are costly to comply with and that carry substantial penalties for failure to comply. In addition, production operations are affected by changing tax and other laws relating to the oil and natural gas industry, constantly changing administrative regulations and possible interruptions or termination by government authorities.

State regulatory authorities have established rules and regulations requiring permits for drilling operations, drilling bonds and reports concerning operations. Most states in which we operate also have statutes and regulations governing a number of environmental and conservation matters, including the unitization or pooling of oil and natural gas properties and establishment of maximum rates of production from oil and natural gas wells. Many states also restrict production to the market demand for oil and natural gas. Such statutes and regulations may limit the rate at which oil and natural gas could otherwise be produced from our properties.

We are subject to extensive and evolving environmental laws and regulations. These regulations are administered by the United States Environmental Protection Agency and various other federal, state, and local environmental, zoning, health and safety agencies, many of which periodically examine our operations to monitor compliance with such laws and regulations. These regulations govern the release of waste materials into the environment, or otherwise relating to the protection of the environment, human, animal and plant health, and affect our operations and costs. In recent years, environmental regulations have taken a cradle to grave approach to waste management, regulating and creating liabilities for the waste at its inception to final disposition. Our oil and natural gas exploration, development and production operations are subject to numerous environmental programs, some of which include solid and hazardous waste management, water protection, air emission controls and situs controls affecting wetlands, coastal operations and antiquities.

Environmental programs typically regulate the permitting, construction and operations of a facility. Many factors, including public perception, can materially impact the ability to secure an environmental construction or operation permit. Once operational, enforcement measures can include significant civil penalties for regulatory violations regardless of intent. Under appropriate circumstances, an administrative agency can request a cease and desist order to terminate operations. New programs and changes in existing programs are anticipated, some of which include natural occurring radioactive materials, oil and natural gas exploration and production waste management and underground injection of waste materials.

Each state in which we operate has laws and regulations governing solid waste disposal, water and air pollution. Many states also have regulations governing oil and natural gas exploration, development and production operations.

We are also subject to federal and state Hazard Communications and Community Right to Know statutes and regulations. These regulations govern record keeping and reporting of the use and release of hazardous substances. We believe we are in compliance with these requirements in all material respects.

 

13

---

Table of Contents

Index to Financial Statements

We may be required in the future to make substantial outlays to comply with environmental laws and regulations. The additional changes in operating procedures and expenditures required to comply with future laws dealing with the protection of the environment cannot be predicted.

Employees

As of December 31, 2007, we had 262 full-time employees. We hire independent contractors on an as needed basis. We have no collective bargaining agreements with our employees. We believe that our employee relationships are satisfactory.

Access to Company Reports

We file periodic reports, proxy statements and other information with the SEC in accordance with the requirements of the Securities Exchange Act of 1934, as amended. We make our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and Forms 3, 4 and 5 filed on behalf of directors and officers, and any amendments to such reports available free of charge through our corporate website at www.petrohawk.com as soon as reasonably practicable after such reports are filed with, or furnished to, the SEC. In addition, our corporate governance guidelines, code of conduct, code of ethics for our chief executive officer (CEO) and senior financial officers, audit committee charter, compensation committee charter and nominating committee charter are available on our website. Within the time period required by the SEC and the New York Stock Exchange (NYSE), as applicable, we will post on our website any modifications to the code of conduct and the code of ethics for our CEO and senior financial officers and any waivers applicable to senior officers as defined in the applicable code, as required by the Sarbanes-Oxley Act of 2002. You may also read and copy any document we file with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. In addition, our reports, proxy and information statements, and our other filings are also available to the public over the internet at the SEC’s website at www.sec.gov.

 

ITEM 1A.

RISK FACTORS

Oil and natural gas prices are volatile, and low prices could have a material adverse impact on our business.

Our revenues, profitability and future growth and the carrying value of our properties depend substantially on prevailing oil and natural gas prices. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow and raise additional capital. The amount we will be able to borrow under our senior revolving credit facility will be subject to periodic redetermination based in part on changing expectations of future prices. Lower prices may also reduce the amount of oil and natural gas that we can economically produce and have an adverse effect on the value of our properties.

Historically, the markets for oil and natural gas have been volatile, and they are likely to continue to be volatile in the future. Among the factors that can cause volatility are:

 

•

the domestic and foreign supply of oil and natural gas;

 

•

the ability of members of the Organization of Petroleum Exporting Countries and other producing countries to agree upon and maintain oil prices and production levels;

 

•

political instability, armed conflict or terrorist attacks, whether or not in oil or natural gas producing regions;

 

•

the level of consumer product demand;

 

•

the growth of consumer product demand in emerging markets, such as China;

 

•

labor unrest in oil and natural gas producing regions;

 

•

weather conditions, including hurricanes and other natural occurrences that affect the supply and/or demand of oil and natural gas;

 

14

---

Table of Contents

Index to Financial Statements

•

the price and availability of alternative fuels;

 

•

the price of foreign imports;

 

•

worldwide economic conditions; and

 

•

the availability of liquid natural gas imports.

These external factors and the volatile nature of the energy markets make it difficult to estimate future prices of oil and natural gas.

Unless we replace our reserves, our reserves and production will decline, which would adversely affect our financial condition, results of operations and cash flows.

In general, the volume of production from oil and natural gas properties declines as reserves are depleted. Our reserves will decline as they are produced unless we acquire properties with proved reserves or conduct successful development and exploration activities. Thus, our future oil and natural gas production and, therefore, our cash flow and income are highly dependent upon our level of success in finding or acquiring additional reserves. However, we cannot assure you that our future acquisition, development and exploration activities will result in any specific amount of additional proved reserves or that we will be able to drill productive wells at acceptable costs.

The successful acquisition of producing properties requires an assessment of a number of factors. These factors include recoverable reserves, future oil and natural gas prices, operating costs and potential environmental and other liabilities, title issues and other factors. Such assessments are inexact and their accuracy is inherently uncertain. In connection with such assessments, we perform a review of the subject properties that we believe is thorough. However, there is no assurance that such a review will reveal all existing or potential problems or allow us to fully assess the deficiencies and capabilities of such properties. We cannot assure you that we will be able to acquire properties at acceptable prices because the competition for producing oil and natural gas properties is intense and many of our competitors have financial and other resources that are substantially greater than those available to us.

Our bank lenders can limit our borrowing capabilities, which may materially impact our operations.

As of December 31, 2007, we had approximately $1.6 billion of long-term debt. As of December 31, 2007, the borrowing base under our senior revolving credit facility was $675 million and we had outstanding borrowings under the facility of $570 million. On February 5, 2008, our borrowing base was increased to $1 billion. The borrowing base limitation under our senior revolving credit facility is semi-annually redetermined. Redeterminations are based upon a number of factors, including commodity prices and reserve levels. Upon a redetermination, our borrowing base could be substantially reduced. We utilize cash flow from operations, bank borrowings and debt and equity financings to fund our development, acquisition and exploration activities. A reduction in our borrowing base could limit our activity in this regard. In addition, we may significantly alter our capitalization in order to make future acquisitions or develop our properties. These changes in capitalization may significantly increase our level of debt. If we incur additional debt for these or other purposes, the related risks that we now face could intensify. A higher level of debt also increases the risk that we may default on our debt obligations. Our ability to meet our debt obligations and to reduce our level of debt depends on our future performance which is affected by general economic conditions and financial, business and other factors. Many of these factors are beyond our control. Our level of debt affects our operations in several important ways, including the following:

 

•

a portion of our cash flow from operations is used to pay interest on borrowings;

 

•

the covenants contained in the agreements governing our debt limit our ability to borrow additional funds, pay dividends, dispose of assets or issue shares of preferred stock and otherwise may affect our flexibility in planning for, and reacting to, changes in business conditions;

 

15

---

Table of Contents

Index to Financial Statements

•

a high level of debt may impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate or other purposes;

 

•

a more leveraged financial position would make us more vulnerable to economic downturns and could limit our ability to withstand competitive pressures; and

 

•

any debt that we incur under our senior revolving credit facility will be at variable rates which make us vulnerable to increases in interest rates.

Our ability to finance our business activities will require us to generate substantial cash flow.

Our business activities require substantial capital. For 2008, we have budgeted capital expenditures of $800 million. We intend to finance our capital expenditures in the future primarily through cash flow from operations as well as additional borrowings under our senior revolving credit facility. We cannot be sure that our business will continue to generate cash flow at or above current levels. Future cash flows and the availability of financing will be subject to a number of variables, such as:

 

•

the level of production from existing wells;

 

•

prices of oil and natural gas;

 

•

our results in locating and producing new reserves;

 

•

the success and timing of development of proved undeveloped reserves; and

 

•

general economic, financial, competitive, legislative, regulatory and other factors beyond our control.

If we are unable to generate sufficient cash flow from operations to fund our budgeted drilling expenditures and/or we are not able to borrow additional funds under our senior revolving credit facility, we may be forced to reduce such expenditures or obtain additional financing through the issuance of debt and/or equity. We cannot be sure that any additional financing will be available to us on acceptable terms. Issuing equity securities to satisfy our financing requirements could cause substantial dilution to our existing stockholders. The level of our debt financing could also materially affect our operations.

If our cash flows were to decrease due to lower oil and natural gas prices, decreased production or other reasons, and if we could not obtain capital through our senior revolving credit facility or otherwise, our ability to execute our development and acquisition plans, replace our reserves or maintain production levels could be greatly limited.

Estimates of proved oil and natural gas reserves are uncertain and any material inaccuracies in these reserve estimates will materially affect the quantities and the value of our reserves.

This report on Form 10-K contains estimates of our proved oil and natural gas reserves. These estimates are based upon various assumptions, including assumptions required by the SEC relating to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating oil and natural gas reserves is complex. This process requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. Therefore, these estimates are inherently imprecise.

Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will vary from those estimated. Any significant variance could materially affect the estimated quantities and the value of our reserves. Our properties may also be susceptible to hydrocarbon drainage from production by other operators on adjacent properties. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control.

At December 31, 2007, approximately 43% of our estimated reserves were classified as proved undeveloped. Estimates of proved undeveloped reserves are less certain than estimates of proved developed

 

16

---

Table of Contents

Index to Financial Statements

reserves. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations. The reserve data assumes that we will make significant capital expenditures to develop our reserves. Although we have prepared estimates of these oil and natural gas reserves and the costs associated with development of these reserves in accordance with SEC regulations, actual capital expenditures will likely vary from estimated capital expenditures, development may not occur as scheduled and actual results may not be as estimated.

We depend substantially on the continued presence of key personnel for critical management decisions and industry contacts.

Our success depends upon the continued contributions of our executive officers and key employees, particularly with respect to providing the critical management decisions and contacts necessary to manage and maintain growth within a highly competitive industry. Competition for qualified personnel can be intense, particularly in the oil and natural gas industry, and there are a limited number of people with the requisite knowledge and experience. Under these conditions, we could be unable to attract and retain these personnel. The loss of the services of any of our executive officers or other key employees for any reason could have a material adverse effect on our business, operating results, financial condition and cash flows.

Our business is highly competitive.

The oil and natural gas industry is highly competitive in many respects, including identification of attractive oil and natural gas properties for acquisition, drilling and development, securing financing for such activities and obtaining the necessary equipment and personnel to conduct such operations and activities. In seeking suitable opportunities, we compete with a number of other companies, including large oil and natural gas companies and other independent operators with greater financial resources, larger numbers of personnel and facilities, and, in some cases, with more expertise. There can be no assurance that we will be able to compete effectively with these entities.

Hedging transactions may limit our potential gains and increase our potential losses.

In order to manage our exposure to price risks in the marketing of our oil and natural gas production, we have entered into oil and natural gas price hedging arrangements with respect to a portion of our anticipated production. We will most likely enter into additional hedging transactions in the future. While intended to reduce the effects of volatile oil and natural gas prices, such transactions may limit our potential gains and increase our potential losses if oil and natural gas prices were to rise substantially over the price established by the hedge. In addition, such transactions may expose us to the risk of loss in certain circumstances, including instances in which:

 

•

our production is less than expected;

 

•

there is a widening of price differentials between delivery points for our production and the delivery point assumed in the hedge arrangement; or

 

•

the counterparties to our hedging agreements fail to perform under the contracts.

Our oil and natural gas activities are subject to various risks which are beyond our control.

Our operations are subject to many risks and hazards incident to exploring and drilling for, producing, transporting, marketing and selling oil and natural gas. Although we may take precautionary measures, many of these risks and hazards are beyond our control and unavoidable under the circumstances. Many of these risks or hazards could materially and adversely affect our revenues and expenses, the ability of certain of our wells to produce oil and natural gas in commercial quantities, the rate of production and the economics of the development of, and our investment in the prospects in which we have or will acquire an interest. Any of these

 

17

---

Table of Contents

Index to Financial Statements

risks and hazards could materially and adversely affect our financial condition, results of operations and cash flows. Such risks and hazards include:

 

•

human error, accidents, labor force and other factors beyond our control that may cause personal injuries or death to persons and destruction or damage to equipment and facilities;

 

•

blowouts, fires, hurricanes, pollution and equipment failures that may result in damage to or destruction of wells, producing formations, production facilities and equipment;

 

•

unavailability of materials and equipment;

 

•

engineering and construction delays;

 

•

unanticipated transportation costs and delays;

 

•

unfavorable weather conditions;

 

•

hazards resulting from unusual or unexpected geological or environmental conditions;

 

•

environmental regulations and requirements;

 

•

accidental leakage of toxic or hazardous materials, such as petroleum liquids or drilling fluids, into the environment;

 

•

hazards resulting from the presence of H2S in gas we produce;

 

•

changes in laws and regulations, including laws and regulations applicable to oil and natural gas activities or markets for the oil and natural gas produced;

 

•

fluctuations in supply and demand for oil and natural gas causing variations of the prices we receive for our oil and natural gas production; and

 

•

the availability of alternative fuels and the price at which they become available.

As a result of these risks, expenditures, quantities and rates of production, revenues and cash operating costs may be materially adversely affected and may differ materially from those anticipated by us.

Governmental and environmental regulations could adversely affect our business.

Our business is subject to federal, state and local laws and regulations on taxation, the exploration for and development, production and marketing of oil and natural gas and safety matters. Many laws and regulations require drilling permits and govern the spacing of wells, rates of production, prevention of waste, unitization and pooling of properties and other matters. These laws and regulations have increased the costs of planning, designing, drilling, installing, operating and abandoning our oil and natural gas wells and other facilities. In addition, these laws and regulations, and any others that are passed by the jurisdictions where we have production, could limit the total number of wells drilled or the allowable production from successful wells, which could limit our revenues.

Our operations are also subject to complex environmental laws and regulations adopted by the various jurisdictions in which we have or expect to have oil and natural gas operations. We could incur liability to governments or third parties for any unlawful discharge of oil, natural gas or other pollutants into the air, soil or water, including responsibility for remedial costs. We could potentially discharge these materials into the environment in any of the following ways:

 

•

from a well or drilling equipment at a drill site;

 

•

from gathering systems, pipelines, transportation facilities and storage tanks;

 

18

---

Table of Contents

Index to Financial Statements

•

damage to oil and natural gas wells resulting from accidents during normal operations; and

 

•

blowouts, hurricanes, cratering and explosions.

Because the requirements imposed by laws and regulations are frequently changed, we cannot assure you that laws and regulations enacted in the future, including changes to existing laws and regulations, will not adversely affect our business. In addition, because we acquire interests in properties that have been operated in the past by others, we may be liable for environmental damage caused by the former operators.

We cannot be certain that the insurance coverage maintained by us will be adequate to cover all losses that may be sustained in connection with all oil and natural gas activities.

We maintain general and excess liability policies, which we consider to be reasonable and consistent with industry standards. These policies generally cover:

 

•

personal injury;

 

•

bodily injury;

 

•

third party property damage;

 

•

medical expenses;

 

•

legal defense costs;

 

•

pollution in some cases;

 

•

well blowouts in some cases; and

 

•

workers compensation.

As is common in the oil and natural gas industry, we will not insure fully against all risks associated with our business either because such insurance is not available or because we believe the premium costs are prohibitive. A loss not fully covered by insurance could have a materially adverse effect on our financial position and results of operations. There can be no assurance that the insurance coverage that we maintain will be sufficient to cover every claim made against us in the future. A loss in connection with our oil and natural gas properties could have a materially adverse effect on our financial position and results of operations to the extent that the insurance coverage provided under our policies cover only a portion of any such loss.

Title to the properties in which we have an interest may be impaired by title defects.

We generally obtain title opinions on significant properties that we drill or acquire. However, there is no assurance that we will not suffer a monetary loss from title defects or title failure. Additionally, undeveloped acreage has greater risk of title defects than developed acreage. Generally, under the terms of the operating agreements affecting our properties, any monetary loss is to be borne by all parties to any such agreement in proportion to their interests in such property. If there are any title defects or defects in assignment of leasehold rights in properties in which we hold an interest, we will suffer a financial loss.

Assets we acquire may prove to be worth less than we paid because of uncertainties in evaluating recoverable reserves and potential liabilities.

Our recent growth is due significantly to acquisitions of exploration and production companies, producing properties and undeveloped leaseholds. We expect acquisitions will also contribute to our future growth. Successful acquisitions require an assessment of a number of factors, including estimates of recoverable reserves, exploration potential, future oil and natural gas prices, operating and capital costs and potential environmental and other liabilities. Such assessments are inexact and their accuracy is inherently uncertain. In connection with our assessments, we perform a review of the acquired properties which we believe is generally consistent with industry practices. However, such a review will not reveal all existing or potential problems. In addition, our

 

19

---

Table of Contents

Index to Financial Statements

review may not permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. We do not inspect every well. Even when we inspect a well, we do not always discover structural, subsurface and environmental problems that may exist or arise. We are generally not entitled to contractual indemnification for preclosing liabilities, including environmental liabilities. Normally, we acquire interests in properties on an “as is” basis with limited remedies for breaches of representations and warranties. As a result of these factors, we may not be able to acquire oil and natural gas properties that contain economically recoverable reserves or be able to complete such acquisitions on acceptable terms.

Our exploration and development drilling efforts and the operation of our wells may not be profitable or achieve our targeted returns.

We require significant amounts of undeveloped leasehold acreage in order to further our development efforts. Exploration, development, drilling and production activities are subject to many risks, including the risk that commercially productive reservoirs will not be discovered. We invest in property, including undeveloped leasehold acreage, which we believe will result in projects that will add value over time. However, we cannot guarantee that all of our prospects will result in viable projects or that we will not abandon our initial investments. Additionally, we cannot guarantee that the leasehold acreage we acquire will be profitably developed, that new wells drilled by us will be productive or that we will recover all or any portion of our investment in such leasehold acreage or wells. Drilling for oil and natural gas may involve unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient net reserves to return a profit after deducting operating and other costs. In addition, wells that are profitable may not achieve our targeted rate of return. Our ability to achieve our target results are dependent upon the current and future market prices for oil and natural gas, costs associated with producing oil and natural gas and our ability to add reserves at an acceptable cost. We rely to a significant extent on 3-D seismic data and other advanced technologies in identifying leasehold acreage prospects and in conducting our exploration activities. The 3-D seismic data and other technologies we use do not allow us to know conclusively prior to our acquisition of leasehold acreage or drilling a well whether oil or gas is present or may be produced economically. The use of 3-D seismic data and other technologies also requires greater pre-drilling expenditures than traditional drilling strategies.

In addition, we may not be successful in controlling and reducing our drilling and production costs in order to improve our overall return. The cost of drilling, completing and operating a well is often uncertain and cost factors can adversely affect the economics of a project. We cannot predict the cost of drilling, and we may be forced to limit, delay or cancel drilling operations as a result of a variety of factors, including:

 

•

unexpected drilling conditions;

 

•

pressure or irregularities in formations;

 

•

equipment failures or accidents and shortages or delays in the availability of drilling rigs and the delivery of equipment;

 

•

adverse weather conditions, including hurricanes; and

 

•

compliance with governmental requirements.

The unavailability or high cost of drilling rigs, equipment, supplies, personnel and oil field services could adversely affect our ability to execute our exploration and development plans on a timely basis and within our budget.

Our industry is cyclical and, from time to time, there is a shortage of drilling rigs, equipment, supplies or qualified personnel. During these periods, the costs and delivery times of rigs, equipment and supplies are substantially greater. In addition, the demand for, and wage rates of, qualified drilling rig crews rise as the number of active rigs in service increases. As a result of increasing levels of exploration and production in response to strong prices of oil and natural gas, the demand for oilfield services has risen, and the costs of these

 

20

---

Table of Contents

Index to Financial Statements

services are increasing, while the quality of these services may suffer. If the unavailability or high cost of drilling rigs, equipment, supplies or qualified personnel were particularly severe in Texas, Oklahoma, Arkansas and Louisiana, we could be materially and adversely affected because our operations and properties are concentrated in those areas. In order to secure drilling rigs in these areas, we have entered into certain contracts with drilling companies that extend over several years. If demand for drilling rigs subsides during the period covered by these contracts, the price we are required to pay may be significantly more than the market rate for similar services.

The marketability of our oil and natural gas production depends on services and facilities that we typically do not own or control. The failure or inaccessibility of any such services or facilities could result in a curtailment of production and revenues.

The marketability of our production depends in part upon the availability, proximity and capacity of gathering systems, pipelines and processing facilities. Pursuant to interruptible or short term transportation agreements, we generally deliver gas through gathering systems and pipelines that we do not own. Under the interruptible transportation agreements, the transportation of our gas may be interrupted due to capacity constraints on the applicable system, for maintenance or repair of the system, or for other reasons as dictated by the particular agreements. If any of the pipelines or other facilities become unavailable, we would be required to find a suitable alternative to transport and process the gas, which could increase our costs and reduce the revenues we might obtain from the sale of the gas.

We depend on the skill, ability and decisions of third party operators to a significant extent.

The success of the drilling, development and production of the oil and natural gas properties in which we have or expect to have a non-operating working interest is substantially dependent upon the decisions of such third-party operators and their diligence to comply with various laws, rules and regulations affecting such properties. The failure of any third-party operator to make decisions, perform their services, discharge their obligations, deal with regulatory agencies, and comply with laws, rules and regulations, including environmental laws and regulations in a proper manner with respect to properties in which we have an interest could result in material adverse consequences to our interest in such properties, including substantial penalties and compliance costs. Such adverse consequences could result in substantial liabilities to us or reduce the value of our properties, which could negatively affect our results of operations.

We may be required to take non-cash asset writedowns if oil and natural gas prices decline.

We may be required under full cost accounting rules to writedown the carrying value of oil and natural gas properties if oil and natural gas prices decline or if there are substantial downward adjustments to our estimated proved reserves, increases in our estimates of development costs or deterioration in our exploration results. We utilize the full cost method of accounting for oil and natural gas exploration and development activities. Under full cost accounting, we are required by SEC regulations to perform a ceiling test each quarter. The ceiling test is an impairment test and generally establishes a maximum, or “ceiling,” of the book value of oil and natural gas properties that is equal to the expected after tax present value (discounted at 10%) of the future net cash flows from proved reserves, including the effect of cash flow hedges when hedge accounting is applied, calculated using prevailing oil and natural gas prices on the last day of the period or a subsequent higher price under certain limited circumstances. If the net book value of oil and natural gas properties (reduced by any related net deferred income tax liability and asset retirement obligation) exceeds the ceiling limitation, SEC regulations require us to impair or “writedown” the book value of our oil and natural gas properties. Depending on the magnitude, a ceiling test writedown could negatively affect our result of operations. As ceiling test computations involve the prevailing oil and natural gas prices, as of a fixed date, it is impossible to predict the likelihood, timing and magnitude of any future impairments. To the extent finding and development costs continue to increase, we will become more susceptible to ceiling test writedowns in lower price environments.

 

21

---

Table of Contents

Index to Financial Statements

Our results of operations could be adversely affected as a result of non-cash goodwill impairments.

In conjunction with the recording of the purchase price allocation for several of our acquisitions including KCS Energy, Inc. (KCS), we recorded goodwill which represents the excess of the purchase price paid by us for those companies plus liabilities assumed, including deferred taxes recorded in connection with the respective acquisitions, over the estimated fair market value of the tangible net assets acquired.

Goodwill is not amortized, but instead must be tested at least annually for impairment by applying a fair value based test. Goodwill is deemed impaired to the extent of any excess of its carrying amount over the residual fair value of the business. Such non-cash impairment could significantly reduce earnings during the period in which the impairment occurs, and would result in a corresponding reduction to goodwill and stockholders’ equity.

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

We have experienced, and expect to continue to experience, substantial capital expenditure and working capital needs, particularly as a result of our drilling program. Our planned capital expenditures for 2008 are expected to exceed the net cash generated by our operations. We expect to use borrowings under our senior revolving credit facility to fund capital expenditures that are in excess of our operating net cash flow and cash on hand. Our ability to borrow under our senior revolving credit facility is subject to certain conditions. If we are not be able to borrow under our senior revolving credit facility to fund our capital expenditures, we may be required to curtail our drilling, development and other activities or be forced to sell some of our assets on an untimely or unfavorable basis. Any such curtailment or sale could have a material adverse effect on our results and future operations.

Our large inventory of undeveloped acreage may create additional economic risk.

Our success is largely dependent upon our ability to develop our large inventory of undeveloped acreage in resource-style plays in Arkansas and Louisiana. To the extent our drilling results are not as successful as we anticipate and/or natural gas and oil prices decline, the return on our investment in the area may not be as attractive as we anticipate.

 

ITEM 1B.

UNRESOLVED STAFF COMMENTS

None.

 

ITEM 2.

PROPERTIES

A description of our properties is included in Item 1. Business and is incorporated herein by reference.

We believe that we have satisfactory title to the properties owned and used in our business, subject to liens for taxes not yet payable, liens incident to minor encumbrances, liens for credit arrangements and easements and restrictions that do not materially detract from the value of these properties, our interests in these properties, or the use of these properties in our business. We believe that our properties are adequate and suitable for us to conduct business in the future.

 

ITEM 3.

LEGAL PROCEEDINGS

A description of our legal proceedings is included in Item 8. Consolidated Financial Statements and Supplementary Data–Note 6, “Commitments, Contingencies and Litigation,” and is incorporated herein by reference.

 

ITEM 4.

SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

No matters were submitted to a vote of our stockholders during the fourth quarter of the fiscal year ended December 31, 2007.

 

22

---

Table of Contents

Index to Financial Statements

PART II.

 

ITEM 5.

MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

On, March 12, 2007, our common stock began trading on the New York Stock Exchange under the symbol HK. Our common stock was traded on the Nasdaq Stock Market under the symbol HAWK from July 16, 2004 through March 11, 2007. Prior to July 16, 2004, our common stock traded on the Nasdaq Stock Market under the symbol BETA. The following table sets forth the quarterly high and low sales prices per share of our common stock as reported on the Nasdaq Stock Market through March 11, 2007 and on the New York Stock Exchange from March 12, 2007 through December 31, 2007.

 

		High			Low
2007
First Quarter		$	13.46		$	10.23
Second Quarter			17.50			12.87
Third Quarter			17.07			13.64
Fourth Quarter			19.11			15.55
2006
First Quarter		$	16.25		$	11.75
Second Quarter			14.64			10.01
Third Quarter			13.00			9.76
Fourth Quarter			13.08			9.90

We have never paid cash dividends on our common stock. We intend to retain earnings for use in the operation and expansion of our business and therefore do not anticipate declaring cash dividends on our common stock in the foreseeable future. Any future determination to pay dividends on common stock will be at the discretion of the board of directors and will be dependent upon then existing conditions, including our prospects, and such other factors, as the board of directors deems relevant. We are also restricted from paying cash dividends on common stock under our senior revolving credit facility and our other long-term debt.

Approximately 605 stockholders of record as of December 31, 2007 held our common stock. In many instances, a registered stockholder is a broker or other entity holding shares in street name for one or more customers who beneficially own the shares.

Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities

We did not purchase any of our equity securities during the fourth quarter of 2007. In addition, we did not sell any of our equity securities which were not registered under the Securities Act of 1933, as amended, during the fourth quarter of 2007.

On January 29, 2008, we entered into an underwriting agreement (the Underwriting Agreement), pursuant to which we sold an aggregate of 18,000,000 shares of our common stock, $0.001 par value (the Common Stock) to the several underwriters named in the Underwriting Agreement (the Underwriters). 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, which was exercised by the Underwriters. These transactions closed on February 1, 2008. The net proceeds from the sale of the Common Stock sold (including Common Shares sold pursuant to the Underwriters’ over-allotment option) were approximately $297.3 million (after deducting underwriting discounts and commissions and estimated expenses).

 

23

---

Table of Contents

Index to Financial Statements

Five-Year Stock Performance Graph

The following common stock performance graph shows the performance of Petrohawk common stock up to December 31, 2007. As required by applicable rules of the SEC, the performance graph shown below was prepared based on the following assumptions:

 

•

A $100 investment was made in Petrohawk common stock and each index on December 31, 2003.

 

•

All quarterly dividends were reinvested at the average of the closing stock prices at the beginning and end of the quarter.

The indices in the performance graph compare the annual cumulative total stockholder return on Petrohawk common stock with the cumulative total return of the Standard and Poor’s 500 Index (S&P 500) and a peer group index comprised of eight U.S. companies engaged in crude oil and natural gas operations whose stocks were traded on NASDAQ or the NYSE during the period from January 1, 2003 through December 31, 2007. The companies that comprise the peer group are Atlas America, Inc. (ATLS), Berry Petroleum Co. (BRY), Cabot Oil & Gas, Corp. (COG), Carrizo Oil &Gas Inc. (CRZO), Continental Resources Inc. (CLR), Denbury Resources Inc. (DNR), EXCO Resources Inc. (XCO), Forest Oil Corp. (FST), Mariner Energy Inc. (ME), Plains Exploration and Production Company (PXP), Quicksilver Resources Inc. (KWK), Range Resource Corp. (RRC), Southwestern Energy Co. (SWN), Stone Energy Corp. (SGY), Swift Energy Co. (SFY), Unit Corp (UNT), Whiting Petroleum Corp. (WLL), collectively referred to as (“Peer Group Index”).

 

		12/31/2003			12/31/2004			12/31/2005			12/31/2006			12/31/2007
Petrohawk		$	100.00		$	217.26		$	335.53		$	291.88		$	439.34
Peer Group		$	100.00		$	178.49		$	240.11		$	235.46		$	350.80
S&P 500		$	100.00		$	108.99		$	112.26		$	127.55		$	132.06

 

24

---

Table of Contents

Index to Financial Statements

ITEM 6.

SELECTED FINANCIAL DATA

The following table presents selected historical financial data derived from our consolidated financial statements. The following data is only a summary and should be read with our historical consolidated financial statements and related notes contained in this document. Our acquisition of KCS Energy, Inc. (KCS) in 2006, Mission Resources Corporation (Mission) in 2005 and of Wynn-Crosby Energy, Inc. and eight of the limited partnerships it owned (Wynn-Crosby) in 2004, affects the comparability between the consolidated financial data for the periods presented.

 

		Years Ended December 31,
		2007				2006				2005				2004			2003
		(In thousands, except per share data)
Income Statement Data:
Oil and gas sales		$	883,405			$	587,762			$	258,039			$	33,577		$	12,925
Income from operations			250,649				154,540				103,890				4,699			1,496
Net income (loss)			52,897				116,563				(16,634	)			8,117			968
Net income (loss) applicable to common stockholders			52,897				116,346				(17,074	)			7,672			521
Earnings (loss) per share of common stock: (1)(2)
Basic		$	0.31			$	0.95			$	(0.31	)		$	0.71		$	0.08
Diluted		$	0.31			$	0.92			$	(0.31	)		$	0.36		$	0.08
Balance sheet data:
Working (deficit) capital		$	(171,304	)		$	(85,307	)		$	(37,905	)		$	8,856		$	2,189
Total assets			4,672,439				4,279,656				1,410,174				534,199			46,115
Total long-term debt (3)			1,595,127				1,326,239				495,801				239,500			13,285
Stockholders’ equity			2,008,897				1,928,344				526,458				247,091			29,270

 

(1)

On May 18, 2004, our Board of Directors approved a one-for-two reverse stock split that was effective May 26, 2004. The reverse stock split was implemented to effect the conditional approval by the Nasdaq National Market of our listing application, which was later formally approved. As a result, all prior year common stock share amounts have been restated to reflect this reverse stock split in the chart above.

(2)	No cash dividends were paid for any periods presented.

(3)	Amount excludes deferred premiums on derivatives which have been classified as current for all periods presented.

 

25

---

Table of Contents

Index to Financial Statements

ITEM 7.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion is intended to assist in understanding our results of operations and our current financial condition. Our consolidated financial statements and the accompanying notes included elsewhere in this Form 10-K contain additional information that should be referred to when reviewing this material.

Statements in this discussion may be forward-looking. These forward-looking statements involve risks and uncertainties, including those discussed below, which could cause actual results to differ from those expressed.

Overview

We are an 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.

At December 31, 2007, our estimated total proved oil and natural gas reserves were approximately 1,062 Bcfe, consisting of 18 MMBbls of oil, and 955 Bcfe of natural gas and natural gas liquids. Approximately 57% of our proved reserves were classified as proved developed. We maintain operational control of approximately 77% of our proved reserves.

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 believe the steps we have taken during 2007 will help us grow production and reserves in resource-style, tight-gas areas in North Louisiana and Arkansas. Our current drilling inventory consists of approximately 10,500 identified locations, 9,000 of which are resource-style.

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.

 

26

---

Table of Contents

Index to Financial Statements

Capital Resources and Liquidity

Our primary sources of cash in 2007, 2006 and 2005 were from operating and financing activities. Proceeds from the issuance of long-term debt and cash received from operations as well as divestitures in those years were offset by cash used in investing activities to complete our acquisition and ongoing drilling activities. Operating cash flow fluctuations were substantially driven by commodity prices and changes in our production volumes. Prices for oil and natural gas have historically been subject to seasonal influences characterized by peak demand and higher prices in the winter heating season; however, the impact of other risks and uncertainties have influenced prices throughout recent years. Working capital was substantially influenced by these variables. Fluctuation in cash flow may result in an increase or decrease in our capital and exploration expenditures. See Comparison of Results of Operations for a review of the impact of prices and volumes on sales. See below for additional discussion and analysis of cash flow.

 

		Years Ended December 31,
		2007				2006				2005
		(In thousands)
Cash flows provided by operating activities		$	605,045			$	296,893			$	135,446
Cash flows used in investing activities			(876,696	)			(972,566	)			(206,109	)
Cash flows provided by financing activities			267,870				668,355				77,914
Net (decrease) increase in cash		$	(3,781	)		$	(7,318	)		$	7,251

Operating Activities. Net cash flows provided by operating activities were $605.0 million, $296.9 million and $135.4 million for the years ended December 31, 2007, 2006 and 2005, respectively. Key drivers of net operating cash flows are commodity prices, production volumes and operating costs.

Net cash flows provided by operating activities increased in 2007 primarily due to our 46% increase in production volumes primarily due to our merger with KCS in July 2006, as well as our 3% increase in our realized natural gas equivalent price. We will have a production decline in 2008 associated with the sale of our Gulf Coast properties which we expect to be partially offset by production increases from the Fayetteville Shale and our North Louisiana properties. In addition, we are also unable to predict future commodity prices. As a result, we are unable to predict future levels of net cash provided by operating activities.

Net cash flows provided by operating activities increased in 2006 primarily due to our 170% increase in production volumes as a result of our acquisition activities as well as our continued drilling success. Also contributing to this increase was our success in reducing our operating costs on a per unit basis as we lowered our lease operating expense to $0.73 per Mcfe in 2006 from $1.04 per Mcfe in 2005. The increase was partially offset by a 16% decrease in our realized natural gas equivalent price compared to 2005.

Net cash provided by operating activities in 2005 increased $117.5 million from 2004. This increase was primarily due to higher commodity prices and an increase in sales volumes in conjunction with the closing of our acquisition of Mission in July 2005, as well as our acquisition of Proton Oil and Gas Corporation (Proton) in February 2005 and the inclusion of a full year of production for Wynn-Crosby which we acquired in November 2004. Average realized prices increased $2.12 from $6.61 per Mcfe in 2004 to $8.73 per Mcfe in 2005. Production volumes increased 24,519 MMcfe from 5,030 MMcfe in 2004 to 29,549 MMcfe in 2005.

Investing Activities. The primary driver of cash used in investing activities was capital spending, inclusive of acquisitions and net of divestitures. Cash used in investing activities was $876.7 million, $972.6 million and $206.1 million for the years ended December 31, 2007, 2006 and 2005, respectively.

In 2007, we spent $764.3 million on capital expenditures in conjunction with our drilling program. We participated in the drilling of 420 gross wells in 2007, of which 15 were dry holes, for a success rate of 96%.

 

27

---

Table of Contents

Index to Financial Statements

On November 30, 2007, we closed the sale of our Gulf Coast properties for $825 million, before customary closing adjustments, consisting of $700 million in cash and a $125 million note from the purchaser (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 economic effective date for the sale was July 1, 2007. Proceeds from the sale were recorded as a decrease to our full cost pool. In conjunction with the closing of this sale, we deposited $650 million with a qualified intermediary to facilitate potential like-kind exchange transactions. At December 31, 2007, we had $269.8 million remaining for use in future acquisitions, all of which was utilized for property acquisitions during the fourth quarter of 2007 and first quarter of 2008.

During the third quarter of 2007, we closed our acquisition of One TEC, LLC, with properties primarily in Arkansas and Texas, for $39.9 million, net of $2.1 million cash acquired.

In addition, we spent $488.9 million primarily to acquire additional interests in the Fayetteville Shale in Arkansas and in both the Elm Grove and Terryville fields in Louisiana. Our program to acquire additional interests and acreage in these fields is ongoing.

Cash used in investing activities in 2006 was $972.6 million. During the fourth quarter of 2006 we sold certain of our oil and natural gas assets in Michigan, Wyoming and California with total estimated reserves of approximately 49 Bcfe. The majority of these assets were acquired in our merger with KCS. Our proceeds from these three separate transactions were approximately $135 million, before customary closing adjustments. The proceeds received in this transaction were used to pay down a portion of our senior revolving credit facility.

On July 12, 2006, we merged with KCS. Total consideration for the shares of KCS common stock consisted of approximately $1.1 billion of our common stock, approximately $450 million in cash and the assumption of $275 million of KCS debt. In addition, all outstanding options to purchase KCS common stock and restricted shares of KCS common stock were converted into options to purchase our common stock or restricted shares of our common stock using an exchange ratio of 2.3706 shares of our common stock to one share of KCS common stock.

During the first quarter of 2006, we completed the acquisition of stock of Winwell for $208 million in cash after customary closing adjustments, and the acquisition of certain oil and natural gas properties for $86 million in cash after customary closing adjustments (collectively referred to as the “North Louisiana Acquisitions”). In conjunction with these acquisitions, we deposited a total of $22.5 million in earnest money that was included in other non-current assets at December 31, 2005 and applied to the overall purchase price in January 2006.

We closed a $52.5 million divestment of substantially all of our properties in the Gulf of Mexico on March 21, 2006. The net proceeds received in this transaction were used to pay down a portion of our senior revolving credit facility. We received an additional $12.6 million in proceeds from the sale of non-operated properties during the third quarter of 2006.

During 2006, we spent an additional $395.5 million on capital expenditures in conjunction with our drilling program. We participated in the drilling of 330 gross wells in 2006, of which 20 were dry holes, for a success rate of 94%.

Cash used in investing activities was $206.1 million in 2005. During the third quarter of 2005, we acquired Mission for consideration consisting of approximately $210 million of our common stock and $96.5 million in cash, net of cash acquired. We also assumed $184 million of Mission’s long-term debt. During the first quarter of 2005, we completed the acquisition of Proton for $52.6 million in cash.

The 2005 acquisitions were offset by the receipt of $88.9 million, primarily from the sale of certain royalty properties. During 2005, we spent $121 million on capital expenditures in conjunction with the drilling of 146 gross wells.

 

28

---

Table of Contents

Index to Financial Statements

Our 2008 capital budget of $800 million, excluding acquisitions, is expected to be funded primarily from cash flows from operations and additional borrowings under our senior revolving credit facility. We establish the budget for these amounts based on our current estimate of future commodity prices, including existing hedges. Due to the volatility of commodity prices, our budget may be periodically adjusted.

Financing Activities. Net cash flows provided by financing activities were $267.9 million, $668.4 million and $77.9 million for the years ended December 31, 2007, 2006 and 2005, respectively.

Cash flows provided by financing activities include net borrowings of $260.4 million, $569.5 million and $95.5 million for the years ended December 31, 2007, 2006 and 2005, respectively, primarily due to our acquisitions activities discussed below as well as our ongoing drilling activities.

In connection with our merger with KCS, on July 12, 2006, we consummated a private placement of 9 ¹/8% senior notes. These notes were issued at 98.735% of the face amount of $650 million for gross proceeds of approximately $642.0 million, before estimated offering expenses and the initial purchasers’ discount. We applied a portion of the net proceeds to fund the $450 million that was paid to KCS stockholders in connection with the merger. We issued an additional $125 million of these notes at 101.125% of the face amount. We applied the net proceeds from the sale of the additional 2013 Notes to repay indebtedness outstanding under our senior revolving credit facility.

In connection with the North Louisiana Acquisitions, on February 1, 2006, we issued and sold 13.0 million shares of our common stock for $14.50 per share, for gross proceeds of $188.5 million. Contemporaneously with the offering, we repurchased 3.3 million shares of our common stock for $46.2 million from EnCap Investments, L.P. and certain of its affiliates. We incurred a total of $10.9 million of offering costs during 2006.

During the third quarter of 2005, we acquired Mission for consideration consisting of approximately $210 million of our common stock and $96.5 million in cash, net of cash acquired. We also assumed $184 million of Mission’s long-term debt.

During the first quarter of 2005, we completed the acquisition of Proton for $52.6 million in cash, as well as the disposition of certain royalty interest properties previously acquired from Wynn-Crosby for approximately $80 million.

Financing activities included $14.6 million and $28.9 million of cash paid on settled derivative contracts that were acquired in conjunction with our acquisition activities in 2006 and 2005, respectively. Financing activities included $3.6 million of cash received on settled derivative contracts in 2007.

In April 2006, we initiated a buyback of our 8% cumulative convertible preferred stock for $9.25 per share, resulting in a $5.3 million use of cash from financing activities.

We believe that we have the ability to finance through new debt or equity offerings, if necessary, our future capital requirements, including acquisitions.

 

29

---

Table of Contents

Index to Financial Statements

Contractual Obligations

We believe we have a significant degree of flexibility to adjust the level of our future capital 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. The following table summarizes our contractual obligations and commitments by payment periods (in thousands).

 

		Payments Due by Period
Contractual Obligations		Total			Less than one year			1-3 years			3-5 years			More than 5 years
Revolving credit facility		$	570,000		$	—		$	570,000		$	—		$	—
9 7/8% senior notes due 2011			254			—			—			254			—
7 1/8% senior notes due 2012 (1)			272,375			—			—			272,375			—
9 1/8% senior notes due 2013 (2)			768,725			—			—			—			768,725
Interest expense on long-term debt (3)			565,638			126,564			236,520			164,558			37,996
Deferred premiums on derivatives (4)			828			828			—			—			—
Rig commitments			69,287			54,999			14,288			—			—
Operating leases			20,028			3,912			7,302			5,591			3,223
Total contractual obligations		$	2,267,135		$	186,303		$	828,110		$	442,778		$	809,944

 

(1)	Excludes $10.4 million of unamortized discount recorded in conjunction with our merger with KCS. See “7 1/8% Senior Notes” below for more details.

(2)	Excludes a net $5.8 million discount recorded in conjunction with the issuance of the notes. See “9 1/8% Senior Notes” below for more details.

(3)	Future interest expense was calculated based on interest rates and amounts outstanding at December 31, 2007 less required annual repayments.

(4)	This amount has been classified as current at December 31, 2007.

The contractual obligations table does not include obligations to taxing authorities due to the uncertainty surrounding the ultimate settlement of amounts and timing of these obligations. In addition, amounts related to our asset retirement obligations are not included in the table above given the uncertainty regarding the actual timing of such expenditures. The total amount of asset retirement obligations at December 31, 2007 is $23.8 million.

Senior Revolving Credit Facility

On October 15, 2007, we entered into the Fourth Amendment (the Fourth Amendment) to Second Amended and Restated Senior Revolving Credit Agreement dated as of July 12, 2006 among us, each of the lenders from time to time party thereto (the Lenders), BNP Paribas, as administrative agent for the Lenders, Bank of America, N.A. and 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, upon the consummation of the sale of the Gulf Coast properties on November 30, 2007, the borrowing base was automatically decreased to $675 million until the next borrowing base redetermination date.

Effective February 5, 2008, we entered into the Fifth Amendment (the Fifth Amendment) to the Second Amended and Restated Senior Revolving Credit Agreement. Pursuant to the Fifth Amendment, our borrowing base under the senior revolving credit facility was increased from $675 million to $1 billion, inclusive of a $100 million component set to expire effective February 5, 2009.

 

30

---

Table of Contents

Index to Financial Statements

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 December 31, 2007, our hedging arrangements exceeded the maximum amount of anticipated projected production of 85%. On February 5, 2008, we entered into the Fifth Amendment to the senior revolving credit facility, which waived the limitation on commodity hedges beginning December 31, 2007 for 2008 so long as the notional volumes for such hedges do not exceed 70% of anticipated total forecasted oil or natural production for each month during 2008. In addition, at December 31, 2007, our current ratio was less than 1.0 to 1.0. As of February 25, 2008, we obtained a waiver for compliance with the current ratio covenant at December 31, 2007.

At December 31, 2007, our borrowing base was $675 million. Amounts outstanding bear interest at specified margins over LIBOR of 1.00% to 1.75% for Eurodollar loans or at specified margins over ABR of 0.00% to 0.50% for ABR loans. Future borrowings above $900 million will carry applicable LIBOR and ABR margins of 2.00% and 0.750%, respectively, as stipulated by the Fifth Amendment. Such margins fluctuate based on the utilization of the facility. Borrowings are secured by first priority liens on substantially all of our assets and all of the assets of, and equity interest in, our subsidiaries. Amounts drawn down on the facility will mature on July 12, 2010.

7 ¹/8% Senior Notes

In our merger with KCS, we assumed (pursuant to the Second Supplemental Indenture relating to the 7  ¹/8% Senior Notes, also referred to as the 2012 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 7 ¹/8% senior notes due 2012. The 2012 Notes are guaranteed on an unsubordinated, unsecured basis by all of our current subsidiaries. Interest on the 2012 Notes is payable semi-annually, on each April 1 and October 1. On or after April 1, 2008, we are permitted to redeem all or a portion of the 2012 Notes at a redemption price equal to 100% of the principal amount plus accrued and unpaid interest, if any, plus a specified premium which decreases annually from 3.568% in 2008 to 0% in 2010 and thereafter.

At December 31, 2007, we were in compliance with all of the debt covenants under the 7 ¹/8% Senior Notes. In conjunction with the assumption of the 7 ¹/8% Notes from KCS, we 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 was $10.4 million at December 31, 2007.

9 ¹/8% Senior Notes

On July 12, 2006, we consummated a private placement of 9 ¹/8% 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 us, our 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. We applied a portion of the net proceeds from the sale of the 2013 Notes to fund the cash paid by us to the KCS stockholders in connection with our merger with KCS and our repurchase of the 9 ⁷/8% notes due 2011 (2011 Notes) pursuant to a tender offer we concluded in July 2006.

At December 31, 2007, we were in compliance with all of our covenants relating to the 2013 Notes. In conjunction with the issuance of the $650 million 2013 Notes, we recorded a discount of $8.2 million to be

 

31

---

Table of Contents

Index to Financial Statements

amortized over the remaining life of the notes utilizing the effective interest rate method. The remaining unamortized discount was $6.9 million at December 31, 2007. In conjunction with the issuance of the additional $125 million 2013 Notes, we 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 December 31, 2007.

9 ⁷/8% Senior Notes

On April 8, 2004, Mission issued $130.0 million of its 9 ⁷/8% senior notes due 2011 (the 2011 Notes). We assumed these notes upon the closing of our merger with Mission. In conjunction with our merger with KCS, we extinguished substantially all of the 2011 Notes for a premium of $14.9 million plus accrued interest of $3.5 million.

Off-Balance Sheet Arrangements

At December 31, 2007, we did not have any off-balance sheet arrangements.

Plan of Operation for 2008

On an annual basis, we expect to fund most of our capital and exploration activities, excluding major oil and natural gas property acquisitions, with cash generated from operations and with borrowings under our senior revolving credit facility. We budget these capital expenditures based on our projected cash flows for the year. We have budgeted $800 million in capital expenditures for 2008.

Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America. The preparation of our consolidated financial statements requires us to make estimates and assumptions that affect our reported results of operations and the amount of reported assets, liabilities and proved oil and natural gas reserves. Some accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. Actual results may differ from the estimates and assumptions used in the preparation of our consolidated financial statements. Described below are the most significant policies we apply in preparing our consolidated financial statements, some of which are subject to alternative treatments under accounting principles generally accepted in the United States of America. We also describe the most significant estimates and assumptions we make in applying these policies. We discussed the development, selection and disclosure of each of these with our audit committee. See Results of Operations above and Item 8. Consolidated Financial Statements and Supplementary Data–Note 1, “Summary of Significant Events and Accounting Policies,” for a discussion of additional accounting policies and estimates made by management.

Oil and Natural Gas Activities

Accounting for oil and natural gas activities is subject to unique rules. Two generally accepted methods of accounting for oil and natural gas activities are available - successful efforts and full cost. The most significant differences between these two methods are the treatment of unsuccessful exploration costs and the manner in which the carrying value of oil and natural gas properties are amortized and evaluated for impairment. The successful efforts method requires unsuccessful exploration costs to be expensed as they are incurred upon a determination that the well is uneconomical while the full cost method provides for the capitalization of these costs. Both methods generally provide for the periodic amortization of capitalized costs based on proved reserve quantities. Impairment of oil and natural gas properties under the successful efforts method is based on an

 

32

---

Table of Contents

Index to Financial Statements

evaluation of the carrying value of individual oil and natural gas properties against their estimated fair value, while impairment under the full cost method requires an evaluation of the carrying value of oil and natural gas properties included in a cost center against the net present value of future cash flows from the related proved reserves, using period-end prices and costs and a 10% discount rate.

Full Cost Method

We use the full cost method of accounting for our oil and natural gas activities. Under this method, all costs incurred in the acquisition, exploration and development of oil and natural gas properties are capitalized into a cost center (the amortization base). Such amounts include the cost of drilling and equipping productive wells, dry hole costs, lease acquisition costs and delay rentals. All general and administrative costs unrelated to drilling activities are expensed as incurred. The capitalized costs of our oil and natural gas properties, plus an estimate of our future development and abandonment costs, are amortized on a unit-of-production method based on our estimate of total proved reserves. Our financial position and results of operations could have been significantly different had we used the successful efforts method of accounting for our oil and natural gas activities.

Proved Oil and Natural Gas Reserves

Estimates of our proved reserves included in this report are prepared in accordance with accounting principles generally accepted in the United States of America and SEC guidelines. Our engineering estimates of proved oil and natural gas reserves directly impact financial accounting estimates, including depreciation, depletion and amortization expense and the full cost ceiling limitation. Proved oil and natural gas reserves are the estimated quantities of oil and natural gas reserves that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under period-end economic and operating conditions. The process of estimating quantities of proved reserves is very complex, requiring significant subjective decisions in the evaluation of all geological, engineering and economic data for each reservoir. The accuracy of a reserve estimate is a function of: (i) the quality and quantity of available data; (ii) the interpretation of that data; (iii) the accuracy of various mandated economic assumptions and (iv) the judgment of the persons preparing the estimate. The data for a given reservoir may change substantially over time as a result of numerous factors, including additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Changes in oil and natural gas prices, operating costs and expected performance from a given reservoir also will result in revisions to the amount of our estimated proved reserves.

Our estimated proved reserves for the years ended December 31, 2007, 2006 and 2005 were prepared by Netherland, Sewell, an independent oil and natural gas reservoir engineering consulting firm. For more information regarding reserve estimation, including historical reserve revisions, refer to Item 8. Consolidated Financial Statements and Supplementary Data—“Supplemental Oil and Gas Information.”

Depreciation, Depletion and Amortization

Our rate of recording depreciation, depletion and amortization expense (DD&A) is primarily dependent upon our estimate of proved reserves, which is utilized in our unit-of-production method calculation. If the estimates of proved reserves were to be reduced, the rate at which we record DD&A expense would increase, reducing net income. Such a reduction in reserves may result from lower market prices, which may make it non-economic to drill for and produce higher cost reserves. A five percent positive or negative revision to proved reserves would decrease or increase the DD&A rate by approximately $0.16 and $0.18 per Mcfe, respectively.

Full Cost Ceiling Limitation

Under the full cost method, we are subject to quarterly calculations of a ceiling or limitation on the amount of our oil and natural gas properties that can be capitalized on our balance sheet. If the net capitalized costs of our

 

33

---

Table of Contents

Index to Financial Statements

oil and natural gas properties exceed the cost center ceiling, we are subject to a ceiling test writedown to the extent of such excess. If required, it would reduce earnings and impact stockholders’ equity in the period of occurrence and result in lower amortization expense in future periods. The discounted present value of our proved reserves is a major component of the ceiling calculation and represents the component that requires the most subjective judgments. However, the associated prices of oil and natural gas reserves that are included in the discounted present value of the reserves do not require judgment. The ceiling calculation dictates that prices and costs in effect as of the last day of the quarter are held constant. However, we may not be subject to a writedown if prices increase subsequent to the end of a quarter in which a writedown might otherwise be required. If oil and natural gas prices decline, even if for only a short period of time, or if we have downward revisions to our estimated proved reserves, it is possible that writedowns of our oil and natural gas properties could occur in the future.

Future Development and Abandonment Costs

Future development costs include costs incurred to obtain access to proved reserves such as drilling costs and the installation of production equipment. Future abandonment costs include costs to dismantle and relocate or dispose of our production facilities, gathering systems and related structures and restoration costs. We develop estimates of these costs for each of our properties based upon their geographic location, type of production structure, well depth, currently available procedures and ongoing consultations with construction and engineering consultants. Because these costs typically extend many years into the future, estimating these future costs is difficult and requires management to make judgments that are subject to future revisions based upon numerous factors, including changing technology and the political and regulatory environment. We review our assumptions and estimates of future development and future abandonment costs on an annual basis. A five percent decrease or increase in future development and abandonment costs would decrease or increase the DD&A rate by approximately $0.05 per Mcfe and $0.06 per Mcfe, respectively.

Asset Retirement Obligations

We have significant obligations to remove tangible equipment and facilities and to restore land at the end of oil and gas production operations. Our removal and restoration obligations are associated with plugging and abandoning wells. Estimating the future restoration and removal costs is difficult and requires us to make estimates and judgments because most of the removal obligations are many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations. Inherent in the present value calculations are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlements and changes in the legal, regulatory, environmental and political environments.

Allocation of Purchase Price in Business Combinations

As part of our business strategy, we actively pursue the acquisition of oil and natural gas properties. The purchase price in an acquisition is allocated to the assets acquired and liabilities assumed based on their relative fair values as of the acquisition date, which may occur many months after the announcement date. Therefore, while the consideration to be paid may be fixed, the fair value of the assets acquired and liabilities assumed is subject to change during the period between the announcement date and the acquisition date. Our most significant estimates in our allocation typically relate to the value assigned to future recoverable oil and natural gas reserves and unproved properties. As the allocation of the purchase price is subject to significant estimates and subjective judgments, the accuracy of this assessment is inherently uncertain.

Under Statement of Financial Accounting Standards (SFAS) SFAS No. 142, Goodwill and Other Intangible Assets, goodwill is not subject to amortization. Rather, goodwill of each reporting unit is tested for impairment on an annual basis, or more frequently if an event occurs or circumstances change that would reduce the fair

 

34

---

Table of Contents

Index to Financial Statements

value of the reporting unit below its carrying amount. The impairment test requires the allocation of goodwill and all other assets and liabilities to reporting units. If the fair value of the reporting unit is less than the book value (including goodwill) then goodwill is reduced to its implied fair value and the amount of the writedown is charged against earnings. We completed our annual impairment review during the third quarter of 2007 and 2006. No impairment was deemed necessary. Downward revisions of estimated reserves or production, increases in estimated future costs or decreases in oil and natural gas prices could lead to an impairment of all or a portion of our goodwill in future periods.

Accounting for Derivative Instruments and Hedging Activities

We utilize derivative contracts to hedge against the variability in cash flows associated with the forecasted sale of our anticipated future oil and natural gas production. We generally hedge a substantial, but varying, portion of our anticipated oil and natural gas production for the next 12-36 months. We do not use derivative instruments for trading purposes. We have elected not to apply hedge accounting to our derivative contracts, which would potentially allow us to not record the change in fair value of our derivative contracts in the statement of operations. We carry our derivatives at fair value on our consolidated balance sheet, with the changes in the fair value included in our statement of operations in the period in which the change occurs. Our results of operations would potentially have been significantly different had we elected and qualified for hedge accounting on our derivative contracts.

 

35

---

Table of Contents

Index to Financial Statements

Comparison of Results of Operations

Year Ended December 31, 2007 Compared to Year Ended December 31, 2006

We had net income of $52.9 million for the year ended December 31, 2007 compared to net income of $116.6 million for 2006. The decrease in net income is primarily due to our pre-tax loss on derivative contracts of $35.0 million in 2007 compared to a pre-tax gain on derivative contracts of $124.4 million in 2006.

The following table summarizes key items of comparison and their related increase (decrease) for the years ended December 31 for the periods indicated.

 

		Years Ended December 31,								Increase (Decrease)
In thousands (except per unit and per Mcfe amounts)		2007				2006
Net income		$	52,897			$	116,563			$	(63,666	)
Oil and gas sales			883,405				587,762				295,643
Expenses:
Production:
Lease operating			64,666				58,029				6,637
Workover and other			7,700				8,118				(418	)
Taxes other than income			58,347				45,547				12,800
Gathering, transportation and other			33,015				16,187				16,828
General and administrative:
General and administrative			58,327				35,827				22,500
Stock-based compensation			15,540				8,242				7,298
Depletion, depreciation and amortization:
Depletion—Full cost			390,180				257,593				132,587
Depreciation—Other			3,231				2,135				1,096
Accretion expense			1,750				1,544				206
Net (loss) gain on derivative contracts:			(35,011	)			124,442				(159,453	)
Interest expense and other			(129,603	)			(89,884	)			(39,719	)
Income tax provision			(33,138	)			(72,535	)			39,397
Production:
Natural Gas—MMcf (1)			99,506				63,643				35,863
Crude Oil—MBbl			2,816				2,703				113
Natural Gas Equivalent—MMcfe			116,402				79,863				36,539
Average Daily Production—MMcfe			319				219				100
Average price per unit (2):
Gas price per Mcf (1)		$	6.92			$	6.57			$	0.35
Oil price per Bbl			68.84				62.27				6.57
Equivalent per Mcfe			7.58				7.34				0.24
Average cost per Mcfe:
Production:
Lease operating			0.56				0.73				(0.17	)
Workover and other			0.07				0.10				(0.03	)
Taxes other than income			0.50				0.57				(0.07	)
Gathering, transportation and other			0.28				0.20				0.08
General and administrative:
General and administrative			0.50				0.45				0.05
Stock-based compensation			0.13				0.10				0.03
Depletion expense			3.35				3.23				0.12

 

(1)	Approximately 4% and 5% of natural gas production represents natural gas liquids (calculated with a 6:1 equivalent ratio) with an average price of $43.70 per Bbl and $36.88 per Bbl for the years ended December 31, 2007 and 2006, respectively.

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

 

36

---

Table of Contents

Index to Financial Statements

For the year ended December 31, 2007, oil and natural gas sales increased $295.6 million, from the same period in 2006, to $883.4 million. The increase for the year was primarily due to the increase in production of 36,539 Mmcfe which was largely due to including a full year of production from properties acquired in our merger with KCS in July 2006. This increase in production led to an approximate $268.2 million increase in revenues from the prior year. The remaining increase of $27.4 million is due to the increase in commodity prices as our realized average price per Mcfe increased $0.24 per Mcfe in 2007 to $7.58 per Mcfe from $7.34 per Mcfe in 2006.

Lease operating expense increased $6.6 million from the prior year. However, on a per unit basis, lease operating expense decreased 23% from $0.73 per Mcfe in 2006 to $0.56 per Mcfe in 2007. The decrease is primarily due to our continued cost control efforts to lower our lease operating expense. We continue to identify divestment prospects which tend to be outlying, higher operating cost properties. Also contributing to the decline on a per unit basis was our acquisition of lower cost properties in our merger with KCS and properties acquired in the North Louisiana Acquisitions.

Workover and other expense decreased $0.4 million for the year ended December 31, 2007 as compared to 2006. The decrease was primarily due to the decrease in major maintenance activities in 2007. On a per unit basis, workover and other expense decreased $0.03 per Mcfe to $0.07 per Mcfe in 2007 compared to $0.10 per Mcfe in 2006.

Taxes other than income increased $12.8 million for the year ended December 31, 2007 as compared to the same period in 2006. The largest components of taxes other than income are production and severance taxes which are generally assessed as a percentage of gross oil and natural gas sales. On a per unit basis, taxes other than income decreased $0.07 per Mcfe to $0.50 per Mcfe in 2007 as compared to $0.57 per Mcfe in 2006. As a percentage of oil and natural gas sales, taxes other than income decreased from 8% in 2006 to 7% in 2007 primarily due to the receipt of tax refunds.

Gathering, transportation and other expense increased $16.8 million for the year ended December 31, 2007 as compared to the same period in 2006. On a per unit basis, gathering transportation and other increased $0.08 per Mcfe from $0.20 per Mcfe in 2006 to $0.28 per Mcfe in 2007. The overall increase is due to the inclusion of a full year of activity in 2007 associated with our merger with KCS in July 2006 as well as higher costs in the Fayetteville Shale associated with our higher production.

General and administrative expense for the year ended December 31, 2007 increased $22.5 million to $58.3 million compared to $35.8 million for the same period in 2006. This increase was primarily due to the sale of our Gulf Coast properties on November 30, 2007. In connection with the sale of the our 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 on November 30, 2007. Salaries and employee benefits increased by approximately $9.9 million with the inclusion of a full year of KCS employees and annual salary increases for existing employees. Office expenses increased approximately $3.1 million with the full year effect of the merger with KCS as well as new corporate office space in Houston and Tulsa. 

Stock-based compensation increased $7.3 million for the year ended December 31, 2007 as compared to the same period in the prior year. This increase was primarily due to the sale of our Gulf Coast properties on November 30, 2007, as outstanding stock appreciation rights, stock options and restricted share awards to employees whose employment was terminated in connection with the sale were modified to accelerate the vesting of these awards and to extend the exercise period from 90 days to November 30, 2008. As a result of these two modifications, we recognized an additional $2.4 million of stock-based compensation expense in November 2007. The remaining increase of approximately $4.9 million is primarily due to additional equity awards that were issued during 2006 and 2007.

 

37

---

Table of Contents

Index to Financial Statements

Depletion expense increased $132.6 million as compared to the same period in 2006 to $390.2 million for the year ended December 31, 2007. Depletion for oil and natural gas properties is calculated using the unit of production method, which essentially depletes the capitalized costs associated with the evaluated properties plus future development costs based on the ratio of production volume for the current period to total remaining reserve volume for the evaluated properties. On a per unit basis, depletion expense increased $0.12 per Mcfe to $3.35 per Mcfe from $3.23 per Mcfe. This increase is primarily due to our merger with KCS in July 2006 and the North Louisiana Acquisitions in January 2006 which substantially increased our future development costs.

We enter into derivative commodity instruments to hedge our exposure to price fluctuations on our anticipated oil and natural gas production. Consistent with prior years, we have elected not to designate any positions as cash flow hedges for accounting purposes, and accordingly, we recorded the net change in the mark-to-market valuation of these derivative contracts in the consolidated statement of operations. At December 31, 2007, we 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. We recorded a net derivative loss of $35.0 million ($79.0 million unrealized loss and a $44.0 million net gain for cash received on settled contracts) for the year ended December 31, 2007 compared to a net derivative gain of $124.4 million ($134.4 million unrealized gain and $10.0 million cash paid on settled contracts) for the year ended December 31, 2006. This decrease is due to the increase in commodity prices, primarily crude oil as the weighted average of the forward strip used to value our crude oil derivatives increased from $65.40 per Bbl at December 31, 2006 to $91.77 per Bbl at December 31, 2007. Also contributing to this decrease was the increase in the weighted average forward strip used to value our natural gas derivatives which increased from $7.29 per MMbtu at December 31, 2006 to $7.92 per MMbtu at December 31, 2007.

Interest expense and other increased $39.7 million for the year ended December 31, 2007 compared to the same period in 2006. This increase was primarily due to additional debt we incurred in conjunction with our merger with KCS in July 2006 and the closing of the North Louisiana Acquisitions in January 2006. Also contributing to this increase was the increase in our senior revolving credit facility in 2007 which was used to partially fund our acquisition and drilling activities as well as other general corporate purposes.

Income tax expense for the year ended December 31, 2007 decreased $39.4 million from the prior year. The decrease in income tax expense from prior year is primarily due to our pre-tax income of $86.0 million in 2007 compared to pre-tax income of $189.1 million in 2006. The effective tax rates for the years ended December 31, 2007 and 2006 were 38.5% and 38.4%, respectively.

 

38

---

Table of Contents

Index to Financial Statements

Comparison of Results of Operations

Year Ended December 31, 2006 Compared to Year Ended December 31, 2005

We had net income of $116.6 million for the year ended December 31, 2006 compared to a net loss of $16.6 million for 2005. The increase in net income is primarily due to our pre-tax gain on derivative contracts of $124.4 million in 2006 compared to a net loss on derivative contracts of $100.4 million in 2005.

The following table summarizes key items of comparison and their related increase (decrease) for the years ended December 31 for the periods indicated.

 

		Years Ended December 31,								Increase (Decrease)
In thousands (except per unit and per Mcfe amounts)		2006				2005
Net (loss) income		$	116,563			$	(16,634	)		$	133,197
Oil and gas sales			587,762				258,039				329,723
Expenses:
Production:
Lease operating			58,029				30,784				27,245
Workover and other			8,118				3,265				4,853
Taxes other than income			45,547				18,497				27,050
Gathering, transportation and other			16,187				2,030				14,157
General and administrative:
General and administrative			35,827				21,214				14,613
Stock-based compensation			8,242				3,820				4,422
Depletion, depreciation and amortization:
Depletion—Full cost			257,593				72,716				184,877
Depreciation—Other			2,135				666				1,469
Accretion expense			1,544				1,157				387
Net (loss) gain on derivative contracts:			124,442				(100,380	)			224,822
Interest expense and other			(89,884	)			(29,207	)			(60,677	)
Income tax benefit (provision)			(72,535	)			9,063				(81,598	)
Production:
Natural Gas—MMcf (1)			63,643				20,219				43,424
Crude Oil—MBbl			2,703				1,555				1,148
Natural Gas Equivalent—MMcfe			79,863				29,549				50,314
Average Daily Production—MMcfe			219				81				138
Average price per unit (2):
Gas price per Mcf (1)		$	6.57			$	8.46			$	(1.89	)
Oil price per Bbl			62.27				55.62				6.65
Equivalent per Mcfe			7.34				8.73				(1.39	)
Average cost per Mcfe:
Production:
Lease operating			0.73				1.04				(0.31	)
Workover and other			0.10				0.11				(0.01	)
Taxes other than income			0.57				0.63				(0.06	)
Gathering, transportation and other			0.20				0.07				0.13
General and administrative:
General and administrative			0.45				0.72				(0.27	)
Stock-based compensation			0.10				0.13				(0.03	)
Depletion expense			3.23				2.46				0.77

 

(1)	Approximately 5% and 7% of natural gas production represents natural gas liquids (calculated with a 6:1 equivalent ratio) with an average price of $36.88 per Bbl and $40.50 per Bbl for the years ended December 31, 2006 and 2005, respectively.

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

 

39

---

Table of Contents

Index to Financial Statements

For the year ended December 31, 2006, oil and natural gas sales increased $329.7 million, from the same period in 2005, to $587.8 million. The increase for the year was primarily due to the increase in production of 50,314 MMcfe, of which 31,290 MMcfe related to our merger with KCS. The remaining increase in volumes was due to the inclusion of a full year of production for Mission as well as the closing of the North Louisiana Acquisitions in January 2006 as well as our increased drilling success. This increase in production led to an approximate $440.7 million increase in revenues from the prior year which was offset by a decrease in commodity prices that led to an approximate $111.0 million decrease in revenues from the prior year. Our realized average price per Mcfe decreased $1.39 per Mcfe in 2006 to $7.34 per Mcfe from $8.73 per Mcfe in 2005.

Lease operating expenses increased $27.2 million from the prior year. The increase was primarily due to the increase in production volumes as a result of our recent acquisition and divestiture activities, as well as a continued increase in overall activity in 2006. We drilled 330 gross wells in 2006 compared to 146 gross wells in 2005. On a per unit basis, lease operating expenses decreased 30% from $1.04 per Mcfe in 2005 to $0.73 per Mcfe in 2006. The decrease on a per unit basis is primarily due to our continued cost control efforts to lower our lease operating expenses. We continue to identify divestment prospects which tend to be outlying, higher operating cost properties as evident by the transactions that closed during the fourth quarter of 2006. Also contributing to decrease on a per unit basis was our acquisition of lower cost properties as a consequence of our merger with KCS and properties acquired in the North Louisiana Acquisitions.

Workover and other expense increased $4.9 million for the year ended December 31, 2006 as compared to 2005. The increase was primarily due to the increase in major maintenance activities in 2006. On a per unit basis, workover and other expense decreased $0.01 per Mcfe to $0.10 per Mcfe in 2006 as our increase in production volume has exceeded the increase in workover expense.

Taxes other than income increased $27.1 million for the year ended December 31, 2006 as compared to the same period in 2005. 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. On a per unit basis, taxes other than income decreased $0.06 per Mcfe to $0.57 per Mcfe in 2006 as compared to $0.63 per Mcfe in 2005. As a percentage of oil and natural gas sales, taxes other than income increased from 7% in 2005 to 8% in 2006 primarily due to our merger with KCS in July 2006.

Gathering, transportation and other expense increased $14.2 million for the year ended December 31, 2006 as compared to the same period in 2005. This increase is due to our recent acquisition activities including the completion of our merger with KCS as well as the North Louisiana Acquisitions.

General and administrative expense for the year ended December 31, 2006 increased $14.6 million to $35.8 million compared to $21.2 million in the same period in 2005. This increase was due to our continued growth over the past two years. In 2006, we completed the North Louisiana Acquisitions as well as our merger with KCS which increased compensation and other costs associated with increased staffing levels to meet the demands of our expanding operations. General and administrative expense has decreased significantly on a per Mcfe basis from $0.72 per Mcfe in 2005 to $0.45 per Mcfe in 2006 as production increases have exceeded our administrative expense increases. Operating in concentrated areas helps us to better control our overhead by enabling us to manage a greater amount of acreage with fewer employees and minimize incremental costs of increased drilling and production. Our strategy of targeting our operations in relatively focused areas permits us to more efficiently manage our general and administrative expenses.

Stock-based compensation increased $4.4 million for the year ended December 31, 2006 as compared to the same period in the prior year. This increase is primarily related to additional stock options and restricted stock grants assumed as part of our merger with KCS in July 2006, as well as the stock options and restricted stock grants given to employees and non-employee directors during 2006 and a full year of amortization for those grants that were issued during 2005.

 

40

---

Table of Contents

Index to Financial Statements

Depletion expense increased $184.9 million from the same period in 2005 to $257.6 million for the year ended December 31, 2006. Depletion for oil and natural gas properties is calculated using the unit of production method, which essentially depletes the capitalized costs associated with the evaluated properties plus future development costs based on the ratio of production volume for the current period to total remaining reserve volume for the evaluated properties. On a per unit basis, depletion expense increased $0.77 per Mcfe to $3.23 from $2.46 per mcfe. This increase was due to our merger with KCS in July 2006, the North Louisiana Acquisitions in January 2006 and our merger with Mission in July 2005.

We enter into derivative commodity instruments to hedge our exposure to price fluctuations on our anticipated oil and natural gas production. Consistent with the prior year, we have elected not to designate any positions as cash flow hedges for accounting purposes, and accordingly, we recorded the net change in the mark-to-market valuation of these derivative contracts in the consolidated statement of operations. At December 31, 2006, we had a $75.2 million derivative asset, $68.2 million of which was classified as current, and a $19.8 million derivative liability, $8.0 million of which was classified as current. We recorded a net derivative gain of $124.4 million ($134.4 million unrealized gain and $10.0 million cash paid on settled contracts) for the year ended December 31, 2006 compared to a net derivative loss of $100.4 million in the prior year. The increase in our net derivative gain in the current year over the net derivative loss in the prior year is due to the decrease in commodity prices.

Interest expense and other increased $60.7 million for the year ended December 31, 2006 compared to the same period in 2005. This increase was primarily due to additional debt we incurred in conjunction with our merger with KCS in July 2006, our merger with Mission in July 2005 and the closing of the North Louisiana Acquisitions in January 2006, as well as premiums paid to extinguish previously assumed Mission debt.

Income tax expense for the year ended December 31, 2006 increased $81.6 million from the prior year. The increase in income tax expense from prior year is primarily due to our pre-tax income of $189.1 million in 2006 compared to a pre-tax loss of $25.7 million in 2005. The effective tax rates for the years ended December 31, 2006 and 2005 were 38.4% and 35.3%, respectively. The increase in our effective tax rate from the prior year is primarily due to changes in state apportionment percentages due to the merger of KCS properties with historical Petrohawk properties. Also adding to this increase was an increase in our effective tax rate for the recognition of a change in the Texas state franchise tax rate due to a change in the tax law. In May 2006, the State of Texas enacted substantial changes to its tax structure beginning in 2007 by imposing a new tax based upon modified gross revenue referred to as the “Margin Tax.” We determined the “Margin Tax” to be an income tax as defined under Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes.

Related Party Transactions

A description of our related party transactions is included in Item 8. Consolidated Financial Statements and Supplementary Data–Note 10, “Related Party Transactions,” and is incorporated herein by reference.

Recently Issued Accounting Standards

We discuss recently adopted and issued accounting standards in Item 8. Consolidated Financial Statements and Supplementary Data–Note 1, “Summary of Significant Events and Accounting Policies.”

 

41

---

Table of Contents

Index to Financial Statements

ITEM 7A.

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 8. Consolidated Financial Statements and Supplementary Data– Note 7, “Derivative and Hedging Activities” for additional information.

Fair Market Value of Financial Instruments

The estimated fair values for financial instruments under Financial Accounting Standards Board Statement No. 107, Disclosures about Fair Value of Financial Instruments, are determined at discrete points in time based on relevant market information. These estimates involve uncertainties and cannot be determined with precision. The estimated fair value of cash, cash equivalents, accounts receivable and accounts payable approximates their carrying value due to their short-term nature. Please refer to “Fair Value of Financial Instruments” in Item 8. Consolidated Financial Statements and Supplementary Data–Note 1, “Summary of Significant Events and Accounting Policies” for additional information.

Interest Sensitivity

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

At December 31, 2007, total debt was $1.6 billion, of which approximately 65% bears interest at a weighted average fixed interest rate of 8.6% per year. The remaining 35% of our total debt balance at December 31, 2007 bears interest at floating or market interest rates that at our option are tied to prime rate or LIBOR. Fluctuations in market interest rates will cause our annual interest costs to fluctuate. At December 31, 2007, the interest rate on our variable rate debt was 6.4% per year. If the balance of our bank debt at December 31, 2007 were to remain constant, a 10% change in market interest rates would impact our cash flow by approximately $1.0 million per quarter.

 

42

---

Table of Contents

Index to Financial Statements

ITEM 8.

CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

 

		Page
Management’s Report on Internal Control Over Financial Reporting		44
Report of Independent Registered Public Accounting Firm		45
Consolidated Statements of Operations for the Years Ended December 31, 2007, 2006 and 2005		46
Consolidated Balance Sheets at December 31, 2007 and 2006		47
Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, 2007, 2006 and 2005		48
Consolidated Statements of Cash Flows for the Years Ended December 31, 2007, 2006 and 2005		49
Notes to the Consolidated Financial Statements		50
Supplemental Oil and Gas Information (Unaudited)		80
Selected Quarterly Financial Data (Unaudited)		83

 

43

---

Table of Contents

Index to Financial Statements

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Management, including the Company’s Chief Executive Officer and Chief Financial Officer, is responsible for establishing and maintaining adequate internal control over financial reporting for the Company. The Company’s internal control system was designed to provide reasonable assurance to the Company’s Management and Directors regarding the preparation and fair presentation of published financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management conducted an evaluation of the effectiveness of internal control over financial reporting based on the Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that Petrohawk Energy Corporation’s internal control over financial reporting was effective as of December 31, 2007.

 

/s/    FLOYD C. WILSON				/s/    MARK J. MIZE
Floyd C. Wilson				Mark J. Mize
Chairman of the Board, President and Chief Executive Officer				Executive Vice President, Chief Financial Officer and Treasurer

Houston, Texas

February 27, 2008

 

44

---

Table of Contents

Index to Financial Statements

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders of

Petrohawk Energy Corporation

Houston, Texas

We have audited the accompanying consolidated balance sheets of Petrohawk Energy Corporation and subsidiaries (the “Company”) as of December 31, 2007 and 2006, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2007. We also have audited the Company’s internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on these financial statements and an opinion on the Company’s internal control over financial reporting based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Petrohawk Energy Corporation and subsidiaries as of December 31, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2007, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

February 26, 2008

 

45

---

Table of Contents

Index to Financial Statements

PETROHAWK ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share amounts)

 

		Years Ended December 31,
		2007				2006				2005
Operating revenues:
Oil and gas		$	883,405			$	587,762			$	258,039
Operating expenses:
Production:
Lease operating			64,666				58,029				30,784
Workover and other			7,700				8,118				3,265
Taxes other than income			58,347				45,547				18,497
Gathering, transportation and other			33,015				16,187				2,030
General and administrative			73,867				44,069				25,034
Depletion, depreciation and amortization			395,161				261,272				74,539
Total operating expenses			632,756				433,222				154,149
Income from operations			250,649				154,540				103,890
Other (expenses) income:
Net (loss) gain on derivative contracts			(35,011	)			124,442				(100,380	)
Interest expense and other			(129,603	)			(89,884	)			(29,207	)
Total other (expenses) income			(164,614	)			34,558				(129,587	)
Income (loss) before income taxes			86,035				189,098				(25,697	)
Income tax (provision) benefit			(33,138	)			(72,535	)			9,063
Net income (loss)			52,897				116,563				(16,634	)
Preferred dividends			—				(217	)			(440	)
Net income (loss) available to common stockholders		$	52,897			$	116,346			$	(17,074	)
Earnings (loss) per share of common stock:
Basic		$	0.31			$	0.95			$	(0.31	)
Diluted		$	0.31			$	0.92			$	(0.31	)
Weighted average shares outstanding:
Basic			168,006				122,452				54,752
Diluted			171,248				126,135				54,752

 

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

 

46

---

Table of Contents

Index to Financial Statements

PETROHAWK ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS

(In thousands, except share and per share amounts)

 

		December 31,
		2007				2006
Current assets:
Cash		$	1,812			$	5,593
Accounts receivable			148,138				155,582
Current portion of deferred income taxes			5,855				—
Receivables from derivative contracts			12,369				68,234
Prepaid expenses and other			21,019				17,303
Total current assets			189,193				246,712
Oil and gas properties (full cost method):
Evaluated			3,247,304				2,901,649
Unevaluated			677,565				537,611
Gross oil and gas properties			3,924,869				3,439,260
Less—accumulated depletion			(769,197	)			(379,017	)
Net oil and gas properties			3,155,672				3,060,243
Other operating property and equipment:
Gross other operating property and equipment			18,940				9,542
Less—accumulated depreciation			(6,838	)			(3,742	)
Net other operating property and equipment			12,102				5,800
Other noncurrent assets:
Goodwill			933,945				938,584
Debt issuance costs, net of amortization			12,052				14,987
Receivables from derivative contracts			—				6,995
Restricted cash (Note 2)			269,837				—
Note receivable			96,098				—
Other			3,540				6,335
Total assets		$	4,672,439			$	4,279,656
Current liabilities:
Accounts payable and accrued liabilities		$	331,471			$	295,951
Current portion of deferred income taxes			—				22,382
Liabilities from derivative contracts			28,198				7,986
Current portion of long-term debt			828				5,700
Total current liabilities			360,497				332,019
Long-term debt			1,595,127				1,326,239
Liabilities from derivative contracts			6,915				11,803
Asset retirement obligations			23,800				45,326
Deferred income taxes			674,968				633,883
Other noncurrent liabilities			2,235				2,042
Commitments and contingencies (Note 6)
Stockholders’ equity:
Common stock: 300,000,000 shares of $.001 par value authorized; 171,220,817 and 168,486,732 shares issued and outstanding at December 31, 2007 and 2006, respectively			171				169
Additional paid-in capital			1,871,516				1,843,862
Retained earnings			137,210				84,313
Total stockholders’ equity			2,008,897				1,928,344
Total liabilities and stockholders’ equity		$	4,672,439			$	4,279,656

 

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

 

47

---

Table of Contents

Index to Financial Statements

PETROHAWK ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(In thousands)

 

		Preferred							Common							Additional Paid-in Capital				Treasury Stock				(Accumulated Deficit) Retained Earnings				Total Stockholders’ Equity
		Shares			Amount				Shares			Amount
Balances at December 31, 2004		598			$	1			39,788			$	40			$	262,045			$	(36	)		$	(14,959	)		$	247,091
Equity compensation vesting																	3,449												3,449
Common stock issued for purchase of Mission Resources									19,565				19				209,909												209,928
Conversion of PHAWK LLC Note									8,750				9				34,991												35,000
Warrants exercised									1,645				2				(2	)											—
Equity related to Mission’s vested options																	27,302												27,302
Preferred stock dividends																									(440	)			(440	)
Repurchase of preferred stock		(5	)			—											(46	)											(46	)
Common stock issuances									3,818				4				12,517												12,521
Tax benefit from exercise of stock options																	8,287												8,287
Net loss																									(16,634	)			(16,634	)
Balances at December 31, 2005		593			$	1			73,566			$	74			$	558,452			$	(36	)		$	(32,033	)		$	526,458
Equity compensation vesting																	10,618												10,618
Common stock issued for purchase of KCS Energy, Inc.									83,862				84				1,146,518												1,146,602
Sale of common stock									13,000				13				188,487												188,500
Encap shares retired									(3,322	)			(3	)			(46,197	)											(46,200	)
Preferred stock dividends																									(217	)			(217	)
Repurchase of preferred stock		(593	)			(1	)										(5,487	)											(5,488	)
Retirement of Treasury shares									(8	)			—				(36	)			36								—
Common stock issuances									1,389				1				2,449												2,450
Offering costs																	(10,942	)											(10,942	)
Net income																									116,563				116,563
Balances at December 31, 2006		—			$	—			168,487			$	169			$	1,843,862			$	—			$	84,313			$	1,928,344
Equity compensation vesting																	22,230												22,230
Warrants exercised									575																				—
Common stock issuances									2,159				2				2,427												2,429
Tax benefit from exercise of stock options																	2,997												2,997
Net income																									52,897				52,897
Balances at December 31, 2007		—			$	—			171,221			$	171			$	1,871,516			$	—			$	137,210			$	2,008,897

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

 

48

---

Table of Contents

Index to Financial Statements

PETROHAWK ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

 

		Years Ended December 31,
		2007				2006				2005
Cash flows from operating activities:
Net income (loss)		$	52,897			$	116,563			$	(16,634	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation and amortization			395,161				261,272				74,539
Income tax provision (benefit)			33,138				72,535				(9,063	)
Stock-based compensation			15,540				8,242				3,820
Net unrealized loss (gain) on derivative contracts			79,011				(134,428	)			64,180
Net realized (gain) loss on derivative contracts acquired			(3,615	)			14,646				28,931
Other			5,664				1,469				(64	)
Change in assets and liabilities, net of acquisitions:
Accounts receivable			18,554				(16,664	)			(17,472	)
Prepaid expenses and other			(3,372	)			(6,373	)			114
Accounts payable and accrued liabilities			11,846				(19,231	)			7,828
Other			221				(1,138	)			(733	)
Net cash provided by operating activities			605,045				296,893				135,446
Cash flows from investing activities:
Oil and gas capital expenditures			(764,311	)			(395,479	)			(121,041	)
Acquisition of One Tec, LLC, net of cash acquired of $2,145			(39,910	)			—				—
Acquisition of KCS Energy, Inc., net of cash acquired of $8,260			—				(512,344	)			—
Acquisition of Winwell Resources, Inc., net of cash acquired of $14,965			—				(177,264	)			—
Acquisition of Mission Resources Corporation, net of cash acquired of $48,359			—				—				(96,545	)
Acquisition of Proton Oil & Gas Corporation, net of cash acquired of $870			—				—				(52,625	)
Acquisition of oil and gas properties			(488,869	)			(87,893	)			—
Proceeds received from sale of oil and gas properties			689,220				192,424				88,900
Increase in restricted cash			(650,000	)			—				—
Decrease in restricted cash			380,163				—				—
Other			(2,989	)			7,990				(24,798	)
Net cash used in investing activities			(876,696	)			(972,566	)			(206,109	)
Cash flows from financing activities:
Proceeds from exercise of options			6,058				2,850				12,055
Proceeds from issuance of common stock and warrants			—				188,500				—
Acquisition of common stock			—				(46,200	)			—
Proceeds from borrowings			950,000				1,681,183				375,000
Repayment of borrowings			(689,601	)			(1,111,644	)			(279,510	)
Debt issue costs			(834	)			(14,438	)			—
Net realized gain (loss) on derivative contracts acquired			3,615				(14,646	)			(28,931	)
Offering costs			—				(10,942	)			—
Buyback of 8% cumulative preferred stock			—				(5,340	)			—
Other			(1,368	)			(968	)			(700	)
Net cash provided by financing activities			267,870				668,355				77,914
Net (decrease) increase in cash			(3,781	)			(7,318	)			7,251
Cash at beginning of period			5,593				12,911				5,660
Cash at end of period		$	1,812			$	5,593			$	12,911

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

 

49

---

Table of Contents

Index to Financial Statements

PETROHAWK ENERGY CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

 

1.	SUMMARY OF SIGNIFICANT EVENTS AND ACCOUNTING POLICIES

Basis of Presentation and Principles of Consolidation

Petrohawk Energy Corporation (Petrohawk or the Company) is an independent oil and natural gas company engaged in the acquisition, development, production and exploration of oil and natural gas properties located in onshore North America. The Company operates in one segment, oil and natural gas exploration and exploitation. The consolidated financial statements include the accounts of all majority-owned, controlled subsidiaries. All intercompany accounts and transactions have been eliminated. Certain prior year amounts have been reclassified to conform to the current year presentation.

On July 12, 2006, the Company completed its merger with KCS Energy, Inc. (KCS). On July 28, 2005, the Company completed its merger with Mission Resources Corporation (Mission). Refer to Note 2, “Acquisitions and Divestitures”, for more details.

Use of Estimates

The preparation of the Company’s consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires the Company’s management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods. These estimates include oil and natural gas reserve quantities which form the basis for the calculation of amortization of oil and natural gas properties. Management emphasizes that reserve estimates are inherently imprecise and that estimates of more recent reserve discoveries are more imprecise than those for properties with long production histories. Actual results may differ from the estimates and assumptions used in the preparation of the Company’s consolidated financial statements.

Allowance for Doubtful Accounts

The Company establishes provisions for losses on accounts receivable if it determines that it will not collect all or part of the outstanding balance. The Company regularly reviews collectibility and establishes or adjusts the allowance as necessary using the specific identification method. There is no significant allowance for doubtful accounts at December 31, 2007 or 2006.

Oil and Natural Gas Properties

The Company accounts for its oil and natural gas producing activities using the full cost method of accounting as prescribed by the United States Securities and Exchange Commission (SEC). Accordingly, all costs incurred in the acquisition, exploration, and development of proved oil and natural gas properties, including the costs of abandoned properties, dry holes, geophysical costs, and annual lease rentals are capitalized. All general and administrative corporate costs unrelated to drilling activities are expensed as incurred. Sales or other dispositions of oil and natural gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless the ratio of cost to proved reserves would significantly change. Depletion of evaluated oil and natural gas properties is computed on the units of production method based on proved reserves. The net capitalized costs of proved oil and natural gas properties are subject to a full cost ceiling limitation in which the costs are not allowed to exceed their related estimated future net revenues discounted at 10%, net of tax considerations. In accordance with Staff Accounting Bulletin Topic 12.D.3.c., the Company utilizes the prices in effect on a date subsequent to the end of a reporting period in which the full cost ceiling limitation was exceeded at the end of a reporting period.

 

50

---

Table of Contents

Index to Financial Statements

Costs associated with unevaluated properties are excluded from the full cost pool until the Company has made a determination as to the existence of proved reserves. The Company reviews its unevaluated properties at the end of each quarter to determine whether the costs incurred should be transferred to the full cost pool and thereby subject to amortization.

Property, Plant and Equipment Other than Oil and Natural Gas Properties

Other operating property and equipment are stated at the lower of cost or fair market value. Provision for depreciation and amortization is calculated using the straight-line method over the estimated useful lives of the respective assets. The cost of normal maintenance and repairs is charged to operating expense as incurred. Material expenditures, which increase the life of an asset, are capitalized and depreciated over the estimated remaining useful life of the asset. The cost of properties sold, or otherwise disposed of, and the related accumulated depreciation or amortization are removed from the accounts and any gains or losses are reflected in current operations.

Impairment of Long-Lived Assets

In the event that facts and circumstances indicate that the costs of long-lived assets, other than oil and natural gas properties, may be impaired, an evaluation of recoverability would be performed. If an evaluation is required, the estimated future undiscounted cash flows associated with the asset would be compared to the asset’s carrying amount to determine if a writedown to market value or discounted cash flow value is required. Impairment of oil and natural gas properties is evaluated subject to the full cost ceiling as described under the Oil and Natural Gas Properties section above.

Revenue Recognition

Revenues from the sale of oil and natural gas are recognized when the product is delivered at a fixed or determinable price, title has transferred, collectibility is reasonably assured and evidenced by a contract. The Company follows the “sales method” of accounting for its oil and natural gas revenue, so it recognizes revenue on all natural gas or crude oil sold to purchasers, regardless of whether the sales are proportionate to its ownership in the property. A receivable or liability is recognized only to the extent that the Company has an imbalance on a specific property greater than the expected remaining proved reserves.

Concentrations of Credit Risk

The Company operates a substantial portion of its oil and natural gas properties. As the operator of a property, the Company makes full payments for costs associated with the property and seeks reimbursement from the other working interest owners in the property for their share of those costs. The Company’s joint interest partners consist primarily of independent oil and natural gas producers. If the oil and natural gas exploration and production industry in general were adversely affected, the ability of the Company’s joint interest partners to reimburse the Company could be adversely affected.

The purchasers of the Company’s oil and natural gas production consist primarily of independent marketers, major oil and natural gas companies and gas pipeline companies. The Company has not experienced any significant losses from uncollectible accounts. In 2007 and 2005, the Company has one individual purchaser accounting for 10% and 12%, respectively, of its total sales. In 2006, the Company had no individual purchasers accounting for more than 10% of its total sales. The Company does not believe the loss of any one of its purchasers would materially affect the Company’s ability to sell the oil and natural gas it produces. The Company believes other purchasers are available in the Company’s areas of operations.

 

51

---

Table of Contents

Index to Financial Statements

Price Risk Management Activities

The Company follows Financial Accounting Standards Board (FASB) Statement of Financial Accounting Standards (SFAS) No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended by SFAS No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities, an amendment of FASB Statement No. 133 and as amended by SFAS No. 149, Amendment of Statement No. 133 on Derivative Instruments and Hedging Activities. 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 for the years ended December 31, 2007, 2006 and 2005. Accordingly, the Company records the net change in the mark-to-market valuation on its derivative contracts in current earnings as a component of other income and expenses on the consolidated statements of operations.

Income Taxes

The Company accounts for income taxes using the asset and liability method wherein deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which temporary differences are expected to be recovered or settled. Deferred tax assets are reduced by a valuation allowance if, based on the weight of available evidence, it is more likely than not that some portion or all of the deferred tax assets will not be realized.

In July 2006, the FASB issued Financial Interpretation (FIN) 48, Accounting for Uncertainty in Income Taxes—an Interpretation of FASB 109 (FIN 48). FIN 48 created a single model to address accounting for the uncertainty in income tax positions and prescribes a minimum recognition threshold a tax position must meet before recognition in the financial statements.

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

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

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

Included in the Company’s consolidated balance sheet at January 1, 2007 was approximately $2.1 million of liabilities associated with uncertain tax positions in the jurisdictions in which it conducts business offset by reductions to existing deferred tax liabilities. This amount included $0.1 million of accrued interest and penalties. No material amounts have been identified to date that would impact the Company’s effective tax rate. The Company does not anticipate material changes to liabilities related to such uncertain tax positions within the next twelve months. Refer to Note 9, “Income Taxes”, for more details.

 

52

---

Table of Contents

Index to Financial Statements

Generally, the Company’s tax years 2004 through 2007 are either currently under audit or remain open and subject to examination by federal tax authorities or the tax authorities in Arkansas, Louisiana, New Mexico, Oklahoma and Texas, which are the jurisdictions in which the Company has its principal operations. In certain of these jurisdictions, the Company operates through more than one legal entity, each of which may have different open years subject to examination. Additionally, it is important to note that years are technically open for examination until the statute of limitations in each respective jurisdiction expires.

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

Asset Retirement Obligation

In August 2001, the FASB issued SFAS No. 143, Accounting for Asset Retirement Obligations (SFAS 143). The Company adopted this new standard beginning January 1, 2003. SFAS 143 requires that the fair value of an asset retirement cost, and corresponding liability, should be recorded as part of the cost of the related long-lived asset and subsequently allocated to expense using a systematic and rational method. Upon adoption, the Company recorded an asset retirement obligation to reflect the Company’s legal obligations related to future plugging and abandonment of its oil and natural gas wells. The Company estimated the expected cash flow associated with the obligation and discounted the amount using a credit-adjusted, risk-free interest rate. The transition adjustment resulting from the adoption of SFAS 143 was reported as a cumulative effect of a change in accounting principle. At least annually, the Company reassesses the obligation to determine whether a change in the estimated obligation is necessary. The Company evaluates whether there are indicators that suggest the estimated cash flows underlying the obligation have materially changed. Should those indicators suggest the estimated obligation may have materially changed on an interim basis (quarterly), the Company will accordingly update its assessment. Additional retirement obligations increase the liability associated with new oil and natural gas wells as these obligations are incurred.

Goodwill

Goodwill represents the excess of the purchase price over the estimated fair value of the assets acquired net of the fair value of liabilities assumed in the acquisition. SFAS No. 142, Goodwill and Other Intangible Assets (SFAS 142) requires that intangible assets with indefinite lives, including goodwill, be evaluated on an annual basis for impairment or more frequently if an event occurs or circumstances change that could potentially result in an impairment.

The impairment test requires the allocation of goodwill and all other assets and liabilities to reporting units. If the fair value of the reporting unit is less than the book value (including goodwill), then goodwill is reduced to its implied fair value and the amount of the writedown is charged against earnings.

The Company completed its annual impairment review during the third quarters of 2007and 2006. No impairment was deemed necessary. Downward revisions of estimated reserves or production, increases in estimated future costs or decreases in oil and natural gas prices could lead to an impairment of all or a portion of the Company’s goodwill in future periods.

Fair Value of Financial Instruments

The estimated fair values for financial instruments under FASB Statement No. 107, Disclosures about Fair Value of Financial Instruments, are determined at discrete points in time based on relevant market information. These estimates involve uncertainties and cannot be determined with precision. The estimated fair value of cash,

 

53

---

Table of Contents

Index to Financial Statements

cash equivalents, accounts receivable and accounts payable approximates their carrying value due to their short-term nature. The estimated fair value of the Company’s senior revolving credit facility approximates carrying value because the facility’s interest rate approximates current market rates. The following table presents the estimated fair values of the Company’s fixed interest rate debt instruments as of December 31, 2007 and 2006:

 

		December 31, 2007						December 31, 2006
Debt (In thousands)		Carrying Amount			Estimated Fair Value			Carrying Amount			Estimated Fair Value
9 1/8% $775 million senior notes		$	768,725		$	809,083		$	775,000		$	807,938
7 1/8% $275 million senior notes			272,375			260,799			275,000			266,750
9 7/8% senior notes			254			254			254			254
		$	1,041,354		$	1,070,136		$	1,050,254		$	1,074,942

The Company accounts for its derivative activities under the provisions of SFAS 133, Accounting for Derivative Instruments and Hedging Activities, as amended. This statement, as amended, establishes accounting and reporting that every derivative instrument be recorded on the balance sheet as either an asset or liability measured at fair value. See Note 7, “Derivative and Hedging Activities” for more details.

Stock-Based Compensation

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

Prior to adopting SFAS 123(R), the Company adopted SFAS No. 123, Accounting for Stock-Based Compensation (SFAS 123) prospectively, using the fair value recognition method to all employee and director awards granted, modified or settled after January 1, 2003. Prior to the adoption, the Company elected to follow Accounting Principles Board (APB) Opinion No. 25, Accounting for Stock Issued to Employees (APB 25) and related interpretations in accounting for its employee stock options. There were no costs accounted for under APB 25 during the years ended December 31, 2007, 2006 and 2005.

Earnings per Share

Basic earnings per share is calculated by dividing the income or loss available to common stockholders by the weighted average number of shares outstanding for the period. Diluted earnings per share reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock.

401(k) Plan

The Company sponsors a 401(k) tax deferred savings plan, whereby the Company matches a portion of employees’ contributions in cash. Participation in the plan is voluntary and all regular employees of the Company are eligible to participate. The Company charged to expense plan contributions of $2.6 million in 2007, $1.7 million in 2006, and $0.7 million in 2005. The Company matches employee contributions dollar-for-dollar on the first 10% of an employee’s pretax earnings.

 

54

---

Table of Contents

Index to Financial Statements

Recently Issued Accounting Pronouncements

In December 2007, the FASB issued Statement SFAS No. 141, Business Combinations (SFAS 141R), and Statement of Financial Accounting Standards 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 FSP No. FIN 48-1, Definition of Settlement in FASB Interpretation No. 48, (FIN 48-1) which amends 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. In addition, FIN 48-1 provides guidance on determining whether a tax position has been effectively settled. The guidance in FIN 48-1 is 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 has adopted FIN 48-1 and no retroactive adjustments were necessary.

In April 2007, the FASB issued Staff Position (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 is effective for fiscal years beginning after November 15, 2007, with early application allowed. The effects of initial adoption should be recognized as a change in accounting principle through retrospective application for all periods presented. 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 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. If the Company elects the Fair Value Option for certain financial assets and liabilities, the Company will report unrealized gains and losses due to changes in fair value in earnings at each subsequent reporting date. The provisions of SFAS 159 are effective January 1, 2008. The Company is currently assessing the impact, if any, that the adoption of this pronouncement will have on the Company’s operating results, financial position or cash flows.

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

 

55

---

Table of Contents

Index to Financial Statements

2.	ACQUISITIONS AND DIVESTITURES

Acquisitions

KCS Energy, Inc.

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

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

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

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

The Company’s unaudited pro forma results of operations for the year ended December 31, 2006 is presented below to illustrate the approximated pro forma effects on the Company’s results of operations under the purchase method of accounting as if the Company had completed the merger with KCS on January 1, 2006. The unaudited pro forma results of operations do not purport to represent what the results of operations would actually have been if the transactions had in fact occurred on such date or to project the Company’s results of operations for any future date or period.

 

		Year Ended December 31, 2006 (Unaudited)
		(In thousands, except per share amounts)
Pro forma:
Oil and gas sales		$	813,138
Net income available to common stockholders		$	194,463
Basic earnings per share		$	1.17
Diluted earnings per share		$	1.14

 

56

---

Table of Contents

Index to Financial Statements

Other Transactions

Fayetteville Shale

During the last six months of 2007, the Company increased its position in the Fayetteville Shale by acquiring interests that it believes to be strategically located, the vast majority of which represent undeveloped properties. These acquisitions were completed in three separate transactions which closed in July, August and December for total cash consideration of approximately $409 million. In addition, the Company added acreage in the Fayetteville Shale, for approximately $20 million through its ongoing leasing activities.

One TEC, LLC

On August 3, 2007 the Company completed the acquisition of all of the membership interests of One TEC, LLC (One TEC). The aggregate cash consideration paid at closing was approximately $42.0 million after certain closing adjustments. The One TEC acquisition was accounted for using the purchase method of accounting under the accounting standards established in SFAS 141 and SFAS 142. As a result, the assets and liabilities of 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.

North Louisiana Acquisitions

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

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

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

Mission Resources Corporation

On July 28, 2005, the Company and Mission Resources Corporation (Mission), completed a two-step merger transaction which resulted in Mission’s merger with and into the Company. Total consideration for the shares of Mission common stock consisted of approximately $139.5 million in cash and 19.565 million shares of the Company’s common stock. In addition, all outstanding options to purchase Mission common stock were converted into options to purchase Petrohawk common stock using the exchange ratio of 0.7641 shares of

 

57

---

Table of Contents

Index to Financial Statements

Petrohawk common stock per share of Mission common stock underlying each option. The Company assumed Mission’s long-term debt of approximately $184 million.

The Company’s merger with Mission was accounted for using the purchase method of accounting under the accounting standards established in SFAS 141 and SFAS 142. As a result, the assets and liabilities of Mission were included in the Company’s September 30, 2005 consolidated balance sheet. The Company reflected the results of operations of Mission beginning July 28, 2005. The Company recorded the estimated fair values of the assets acquired and liabilities assumed at July 28, 2005, which primarily consisted of oil and natural gas properties of $606.7 million, derivative liabilities of $29.4 million, asset retirement obligations of $37.7 million, a net deferred income tax liability of $134.8 million, and goodwill of $138.9 million. The deferred income tax liability recognizes the difference between the tax basis and the fair value of the acquired oil and natural gas properties. The recorded book value of the oil and natural gas properties was increased and goodwill was recorded to recognize this tax basis differential, none of which is deductible for tax purposes.

Proton Oil & Gas Corporation

On February 25, 2005, the Company acquired the stock of Proton Oil & Gas Corporation (Proton) for $53 million in cash. This privately negotiated transaction had an effective date of January 1, 2005. The properties acquired were located in South Louisiana and South Texas.

The acquisition of Proton was accounted for using the purchase method of accounting. As a result, the assets and liabilities of Proton were included in the Company’s March 31, 2005 consolidated balance sheet. The transaction had an effective date of January 1, 2005 and closed on February 25, 2005. As such, the Company reflected the results of operations of Proton beginning February 25, 2005. The Company recorded a purchase price of approximately $80.4 million of which $26.0 million reflected a non-cash item pertaining to the deferred income taxes attributable to the differences between the tax basis and the fair value of the acquired oil and natural gas properties. Substantially all of the $80.4 million was allocated to oil and natural gas properties.

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 closed 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 December 31, 2007, $3.9 million of the discount remained and is being amortized by the Company over the first 150 days of the Note. In conjunction with the closing of this sale, we deposited $650 million with a qualified intermediary to facilitate potential like-kind exchange transactions. At December 31, 2007, we had $269.8 million remaining for use in future acquisitions, all of which was utilized for property acquisitions during the fourth quarter of 2007 and first quarter of 2008. See Note 12, “Subsequent Events” for more details. This amount was classified as restricted cash as of December 31, 2007.

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.

 

58

---

Table of Contents

Index to Financial Statements

Michigan, Wyoming and California

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

Gulf of Mexico

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

Royalty Interest Properties

On February 25, 2005, the Company completed the disposition of certain royalty interest properties previously acquired from Wynn-Crosby Energy, Inc. to Noble Royalties, Inc. d/b/a Brown Drake Royalties for approximately $80 million in cash. The proceeds from sale were recorded as a decrease to the Company’s full cost pool.

 

3.	OIL AND NATURAL GAS PROPERTIES

Oil and natural gas properties as of December 31, 2007 and 2006 consisted of the following:

 

		December 31,
		2007				2006
		(In thousands)
Subject to depletion		$	3,247,304			$	2,901,649
Not subject to depletion:
Exploration wells in progress			14,818				6,020
Other capital costs:
Incurred in 2007			376,566				—
Incurred in 2006			272,060				457,889
Incurred in 2005 and prior			14,121				73,702
Total not subject to depletion			677,565				537,611
Gross oil and gas properties			3,924,869				3,439,260
Less accumulated depletion			(769,197	)			(379,017	)
Net oil and gas properties		$	3,155,672			$	3,060,243

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

 

59

---

Table of Contents

Index to Financial Statements

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

At December 31, 2007, the Company’s net capitalized costs of proved oil and natural gas properties did not exceed the estimated future net revenues discounted at 10%, net of tax considerations.

At December 31, 2006, the ceiling test value of the Company’s reserves was calculated based on the December 31, 2006 West Texas Intermediate posted price of $57.75 per barrel adjusted by lease for quality, transportation fees, and regional price differentials, and the December 31, 2006 Henry Hub spot market price of $5.63 per million British thermal unit (MMbtu) adjusted by lease for energy content, transportation fees, and regional price differentials. Using these prices, the Company’s net book value of oil and natural gas properties would have exceeded the ceiling amount by approximately $224 million (net of tax) at December 31, 2006. However, subsequent to year-end, the market price for Henry Hub gas and West Texas Intermediate oil increased significantly. As a consequence, prior to February 22, 2007, the Company elected to use prices on February 22, 2007, which were $7.51 per MMbtu for Henry Hub gas and $60.95 per barrel for West Texas Intermediate, adjusted for certain items as discussed above. Utilizing these prices, the Company’s net book value of oil and natural gas properties at December 31, 2006 would not have exceeded the ceiling amount. As a result of the increase in the ceiling amount using the subsequent prices, the Company did not record a writedown of its oil and natural gas property costs.

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.

 

4.	LONG-TERM DEBT

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

 

		December 31,
		2007			2006
		(In thousands)
Senior revolving credit facility		$	570,000		$	295,000
9 1/8% $775 million senior notes (1)			762,934			768,514
7 1/8% $275 million senior notes (2)			261,939			262,471
9 7/8% senior notes			254			254
		$	1,595,127		$	1,326,239

 

(1)

This amount is comprised of the $650.0 million and $125.0 million private placements consummated in July 2006. These amounts include a $6.9 million and $7.8 million discount at December 31, 2007 and 2006, respectively, recorded by the Company in conjunction with the issuance of the $650.0 million notes. Additionally, these amounts include a $1.1 million and $1.3 million premium at December 31, 2007 and 2006, respectively, recorded by the Company in conjunction with the issuance of the $125.0 million notes. See “9 1/8% Senior Notes” below for more details.

(2)	Amount includes a $10.4 million and $12.5 million discount at December 31, 2007 and 2006, respectively, recorded by the Company in conjunction with the assumption of the notes. See “7 1/8% Senior Notes” below for more details.

 

60

---

Table of Contents

Index to Financial Statements

Amounts related to our deferred premiums on derivatives of $0.8 million and $5.7 million have been classified as current at December 31, 2007 and 2006, respectively, and have been excluded from the long-term debt table above.

Senior Revolving Credit Facility

In connection with the Company’s merger with KCS, the Company amended and restated its senior revolving credit facility. The facility provides for a $1 billion commitment with a borrowing base that will be redetermined on a semi-annual basis. Petrohawk and the lenders each have the right to one annual interim unscheduled redetermination to adjust the borrowing base based on the Company’s oil and gas properties, reserves, other indebtedness and other relevant factors.

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. Upon the consummation of the sale of the Gulf Coast properties, the borrowing base was automatically decreased to $675 million until 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 9 ¹/8% senior notes due 2013 and the 7 ¹/8% senior notes due 2012 redeemed or repurchased.

Effective November 30, 2007, the Company’s borrowing base was decreased to $675 million in accordance with the Fourth Amendment upon the closing of the sale of the Company’s Gulf Coast properties. 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. See Note 13, “Subsequent Events” for additional information.

At December 31, 2007, the borrowing base was $675 million. Amounts outstanding bear interest at specified margins over LIBOR of 1.00% to 1.75% for Eurodollar loans or at specified margins over ABR of 0.00% to 0.50% for ABR loans. Such margins fluctuate based on the utilization of the facility. On February 5, 2008, these rates were increased to 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. Amounts drawn down on the facility will mature on July 12, 2010.

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 December 31, 2007, the Company’s hedging arrangements exceeded the maximum amount of anticipated projected production of 85%. On February 5, 2008, the Company and its lenders entered into a fifth amendment to the senior revolving credit facility, as discussed above, which waived the limitation on commodity hedges for 2008 so long as the notional volumes for such hedges do not exceed 70% of anticipated total forecasted oil or natural production for each month during 2008. In addition, at December 31, 2007, the Company’s current ratio was less than 1.0 to 1.0. As of February 25, 2008, the Company had received a waiver for the current ratio requirement at December 31, 2007.

 

61

---

Table of Contents

Index to Financial Statements

7 ¹/8% Senior Notes

Upon effectiveness of the Company’s merger with KCS, the Company assumed (pursuant to the Second Supplemental Indenture relating to the 7 ¹/8% 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 7 ¹/8% 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 price, plus a specified premium (expressed as percentages of principal amount) plus accrued and unpaid interest thereon, if any, to the applicable redemption date:

 

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

At December 31, 2007, the Company is in compliance with all of its debt covenants under the 7 ¹/8% Senior Notes.

In conjunction with the assumption of the 7 ¹/8% 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 $10.4 million at December 31, 2007.

The 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.

9 ¹/8% Senior Notes

On July 12, 2006, the Company consummated its private placement of 9 ¹/8% 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 9 ⁷/8% 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

 

62

---

Table of Contents

Index to Financial Statements

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: (i) 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 (ii) each redemption must occur within 90 days of the date of the closing of the related equity offering.

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

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

 

Year		Percentage
2010		104.563
2011		102.281
2012		100.000

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

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

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 December 31, 2007, 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 $6.9 million at December 31, 2007. In conjunction with the issuance of the $125 million 2013 Notes, the Company recorded a premium of $1.4 million to be amortized over the remaining

 

63

---

Table of Contents

Index to Financial Statements

life of the notes utilizing the effective interest rate method. The remaining unamortized premium was $1.1 million at December 31, 2007.

Repayment of the Second Lien Term Loan Facility

On July 12, 2006, in connection with its entry into the revolving credit facility and the closing of its sale of the 2013 Notes, the Company repaid all amounts outstanding under, and terminated, its Amended and Restated Second Lien Term Loan, dated as of July 28, 2005, between the Company, each of the Lenders from time to time party thereto and BNP Paribas, as administrative agent for the Lenders.

9 ⁷/8% Senior Notes

On April 8, 2004, Mission issued $130.0 million of its 9 ⁷/8% 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 December 31, 2007. In connection with the extinguishment of substantially all of the 2011 Notes, the Company requested and received from the noteholders consent to eliminate most significant debt covenants associated with the 2011 Notes.

Aggregate maturities required on long-term debt at December 31, 2007 are due in future years as follows (amounts in thousands):

 

2008		$	—
2009			—
2010			570,000
2011			254
2012			272,375
Thereafter			768,725
Total		$	1,611,354

Debt Issuance Costs

The Company capitalizes certain direct costs associated with the issuance of long-term debt. At December 31, 2007, the Company has approximately $12.1 million of net debt issuance costs being amortized over the lives of the respective debt.

 

5.	ASSET RETIREMENT OBLIGATION

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

 

64

---

Table of Contents

Index to Financial Statements

The Company recorded the following activity related to the ARO liability for the years ended December 31, 2007 and 2006 (in thousands):

 

Liability for asset retirement obligation as of December 31, 2005		$	51,249
Liabilities settled and divested (1)			(25,675	)
Additions			2,223
Acquisitions (1)			15,985
Accretion expense			1,544
Liability for asset retirement obligation as of December 31, 2006			45,326
Liabilities settled and divested (1)			(26,443	)
Additions			2,754
Acquisitions (1)			414
Accretion expense			1,749
Liability for asset retirement obligation as of December 31, 2007		$	23,800

 

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

 

6.	COMMITMENTS, CONTINGENCIES AND LITIGATION

Contingencies

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

Lease Commitments

The Company leases corporate office space in Houston, Texas and Tulsa, Oklahoma as well as a number of other field office locations. In addition, the Company also has lease commitments related to certain vehicles, machinery and equipment under long-term operating leases. Rent expense was $3.3 million, $2.0 million and $0.7 million for the years ended December 31, 2007, 2006, and 2005, respectively.

As of December 31, 2007, future minimum lease payments for all non-cancelable operating leases are as follows (in thousands):

 

2008		$	3,912
2009			3,756
2010			3,546
2011			3,314
2012			2,277
Thereafter			3,223
Total		$	20,028

 

65

---

Table of Contents

Index to Financial Statements

The Company also has 12 drilling rigs under contract. As of December 31, 2007, the Company is obligated over the next 3 years to pay $69.3 million as follows (in thousands):

 

2008		$	54,999
2009			12,502
2010			1,786
2011			—
2012			—
Thereafter			—
Total		$	69,287

 

7.	DERIVATIVE AND HEDGING ACTIVITIES

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

At 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. The Company elected not to designate any positions as cash flow hedges for accounting purposes, and accordingly, recorded the net change in the mark-to-market valuation of these derivative contracts in the consolidated statement of operations.

At 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. The Company recorded a net derivative loss of $35.0 million ($79.0 million unrealized loss and a $44.0 million net gain for cash received on settled contracts) for the year ended December 31, 2007.

At December 31, 2006, the Company had 94 open positions summarized in the tables below: 73 natural gas price collar arrangements, six natural gas price swap arrangements, two natural gas put options, two crude oil price swap arrangements and 11 crude oil collar arrangements. The Company elected not to designate any positions as cash flow hedges for accounting purposes, and accordingly, recorded the net change in the mark-to-market valuation of these derivative contracts in the consolidated statement of operations.

At December 31, 2006, the Company had a $75.2 million derivative asset, $68.2 million of which was classified as current, and a $19.8 million derivative liability, $8.0 million of which was classified as current. The Company recorded a net derivative gain of $124.4 million ($10.0 million cash paid on settled contracts) for the year ended December 31, 2006.

At December 31, 2005, the Company had 48 open positions: 20 natural gas price collar arrangements, one natural gas price swap arrangement, four natural gas put options, one crude oil price swap arrangement and 22 crude oil collar arrangements. The Company elected not to designate any positions as cash flow hedges for accounting purposes, and accordingly, recorded the net change in the mark-to-market valuation of these derivative contracts in the consolidated statement of operations.

 

66

---

Table of Contents

Index to Financial Statements

At December 31, 2005, the Company had a $3.5 million derivative asset, $1.3 million of which is classified as current, and an $86.8 million derivative liability, $51.1 million of which is classified as current. On the July 28, 2005 merger date, the Company acquired a $29.4 million derivative liability from Mission. At December 31, 2005, the fair value of the derivatives acquired from Mission was $22.7 million. The Company recorded a net derivative loss of $100.4 million for the year ended December 31, 2005.

Natural Gas

At December 31, 2007, the Company had the following natural gas costless collar positions:

 

Collars

Period

Volume in MMbtu’s

Floors

Ceilings

Price / Price Range

Weighted Average Price

Price / Price Range

Weighted Average Price

January 2008 – December 2008

41,090,000

$

5.00 – $8.00

$

7.06

$

6.45 – $19.15

$

10.86

At December 31, 2007, the Company had the following natural gas swap positions:

 

		Swaps
Period		Volume in MMbtu’s		Price / Price Range			Weighted Average Price
January 2008 – December 2008		12,800,000		$	7.71 – $8.28		$	7.96
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 December 31, 2007, the Company had the following natural gas put options:

 

		Floors
Period		Volume in MMbtu’s		Weighted Average Price
January 2008 – December 2008		1,820,000		$	7.00

The Company recorded a deferred premium liability of $0.8 million of long-term debt which has been classified as current at December 31, 2007 based on a weighted average deferred premium of $0.46 per MMbtu. The natural gas put option contracts contain deferred premiums that will be paid as the contracts expire.

Crude Oil

At December 31, 2007, 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

January 2008 – December 2008

792,000

$

34.00 – $70.00

$

64.96

$

45.30 – $85.05

$

80.26

At December 31, 2007, the Company had the following crude oil swap positions:

 

		Swaps
Period		Volume in Bbls		Price / Price Range			Weighted Average Price
January 2008 – December 2008		418,500		$	38.10 – $81.70		$	66.37
January 2009 – December 2009		273,750			76.85 –   77.30			77.00
January 2010 – December 2010		273,750			75.10 –   75.55			75.25

 

67

---

Table of Contents

Index to Financial Statements

8.	STOCKHOLDERS’ EQUITY

On February 1, 2008, the Company completed the sale of 20.7 million shares of its common stock for $297.3 million (after deducting underwriting discounts, commissions and estimated expenses). See Note 13, “Subsequent Events” for additional information.

In connection with the Company’s merger with KCS on July 12, 2006, the Company issued 83.9 million shares of its common stock as consideration to the former stockholders of KCS.

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

For the years ended December 31, 2007, 2006 and 2005, respectively, the Company has recognized $15.5 million, $8.2 million and $3.8 million respectively, of non-cash stock compensation expense.

Incentive Plans

The Company’s Incentive Plans include the Third Amended and Restated 2004 Employee Incentive Plan (2004 Employee Plan), Second Amended and Restated 2004 Non-Employee Director Incentive Plan (2004 Non-Employee Director Plan), Mission Resources Corporation 1994 Stock Incentive Plan (Mission 1994 Plan), Mission Resources Corporation 1996 Stock Incentive Plan (Mission 1996 Plan) and Mission Resources Corporation 2004 Stock Incentive Plan (Mission 2004 Plan), KCS Energy, Inc. 2001 Employee and Directors Stock Plan (KCS 2001 Plan) and the KCS Energy, Inc. 2005 Employee and Directors Stock Plan (KCS 2005 Plan) as of December 31, 2007.

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, which is the maximum term permitted under the 2004 Plan. At the end of the term, the right to receive the value of the stock appreciation right expires.

During the year ended December 31, 2007, the Company granted a combination of stock options and stock appreciation rights covering 1.5 million shares of common stock to employees of the Company. This is comprised of 1.1 million shares from the 2004 Employee Plan and 0.4 million shares from the KCS 2005 Plan. The stock appreciation rights and options have exercise prices ranging from $11.64 to $18.69 with a weighted average of $11.84 and vest over a three year period at a rate of one-third on the annual anniversary date of the grant and expire ten years from the grant date.

 

68

---

Table of Contents

Index to Financial Statements

At December 31, 2007, the unrecognized compensation expense related to non-vested stock appreciation rights and options totaled $1.9 million and will be recognized on a straight line basis over the weighted average remaining vesting period of 2.2 years.

Restricted Stock

In 2007, the Company granted 0.9 million shares of restricted common stock to employees and non-employee directors of the Company. These restricted shares were granted at prices ranging from $11.64 to $18.69 with a weighted average price of $12.52. Employee shares vest over a three-year period at a rate of one-third on the annual anniversary date of the grant and the directors’ shares cliff vest after a six-month period.

In 2006, the Company granted 0.9 million shares of restricted common stock to employees and non-employee directors of the Company. These restricted shares were granted at prices ranging from $9.80 to $16.04 with a weighted average price of $11.72. Employee shares vest over a three-year period at a rate of one-third on the annual anniversary date of the grant and the directors’ shares cliff vest after a six-month period.

In 2006, in conjunction with the Company’s merger with KCS, KCS restricted stock was converted into 0.6 million shares of Petrohawk restricted stock. These shares cliff vest after a three-year period and expire ten years after the date of grant. The Company recognized $1.1 million in compensation cost for the year ended December 31, 2006 and will recognize $3.2 million in future periods related to these shares.

The following table sets forth the restricted stock transactions for the years ended December 31, 2007, 2006 and 2005 (in thousands, except share and per share amounts).

 

		Number of Shares			Weighted Average Grant Date Fair Value Per Share			Aggregate Intrinsic Value (1)
Unvested outstanding shares at December 31, 2004		45,000			$	8.25		$	385
Granted		100,000				10.31
Vested		(71,666	)			8.44
Unvested outstanding shares at December 31, 2005		73,334			$	10.87		$	969
KCS shares assumed in merger		616,238				13.44
Granted		888,888				11.72
Vested		(116,121	)			11.52
Forfeited		(19,494	)			10.72
Unvested outstanding shares at December 31, 2006		1,442,845			$	12.38		$	16,593
Granted		867,100				12.52
Vested		(822,597	)			12.23
Forfeited		(80,505	)			12.46
Unvested outstanding shares at December 31, 2007		1,406,843			$	12.75		$	24,352

 

(1)

The intrinsic value of restricted stock was calculated as the closing market price on December 31, 2007 and 2006 of the underlying stock multiplied by the number of restricted shares. The intrinsic value of the shares vested for the year ended December 31, 2007 and 2006 was $24.4 million and $16.6 million, respectively.

The weighted average grant date fair value of the shares granted in 2007 and 2006 was $10.8 million and $18.3 million, respectively. At December 31, 2007 and 2006, the unrecognized compensation expense related to non-vested restricted stock totaled $7.5 million and $10.4 million, respectively, and will be recognized on a straight line basis over the weighted average remaining vesting period of 1.7 years and 1.9 years, respectively.

 

69

---

Table of Contents

Index to Financial Statements

Warrants, Options and Stock Appreciation Rights

The following table sets forth the warrants, options and stock appreciation rights transactions for the years ended December 31, 2007, 2006 and 2005 (in thousands, except share and per share amounts).

 

		Number			Weighted Average Exercise Price Per Share			Aggregate Intrinsic Value (1)			Weighted Average Remaining Contractual Life (Years)
Outstanding at December 31, 2004		7,000,883			$	5.08		$	24,363		5.4
Assumed in Merger with Mission		3,852,433				3.76
Granted		1,404,300				9.37
Exercised		(5,986,635	)			3.26
Forfeited		(572,434	)			15.01
Outstanding at December 31, 2005		5,698,547			$	6.16		$	40,232		5.6
KCS options assumed in merger		2,585,950				3.96
Granted		1,877,270				11.97
Exercised		(507,342	)			6.08
Forfeited		(428,212	)			14.83
Outstanding at December 31, 2006		9,226,213			$	6.34		$	47,607		6.0
Granted		1,494,100				11.84
Exercised		(2,378,593	)			4.90
Forfeited		(196,072	)			11.96
Outstanding at December 31, 2007		8,145,648			$	7.64		$	78,779		4.9
Exercisable at December 31, 2005		4,417,331			$	5.30		$	34,985		4.3
Exercisable at December 31, 2006		6,814,387			$	4.63		$	46,829		4.9
Exercisable at December 31, 2007		6,251,790			$	5.74		$	72,338		3.4

 

(1)

The intrinsic value of a stock option is the amount by which the current market value of the underlying stock exceeds the exercise price of the option. The aggregate intrinsic value of stock options exercised during the years ended December 31, 2007, 2006 and 2005 was approximately $29.5 million, $2.8 million and $44.0 million, respectively.

There were 11,650 options and 500 options which expired in 2007 and 2006, respectively, and none in 2005. The weighted average grant date fair value of options granted in 2007 and 2006 was $5.4 million and $30.7 million, respectively. At December 31, 2007 and 2006, the unrecognized compensation expense related to non-vested stock options totaled $3.1 million and $5.1 million, respectively, and will be recognized on a straight line basis over the weighted average remaining vesting period of 1.8 years for each period.

In 2006, in conjunction with the Company’s merger with KCS, KCS stock options were converted into 2.6 million of Petrohawk stock options.

The number of shares reserved for the exercise of common stock purchase warrants and stock options under the Company’s incentive plans (as described below) as of December 31, 2007 is 8.1 million at a weighted average price of $7.64.

 

70

---

Table of Contents

Index to Financial Statements

Warrants, options and stock appreciation rights outstanding at December 31, 2007 consisted of the following:

 

Outstanding									Exercisable
Range of Exercise Prices Per Share		Number		Weighted Average Exercise Price per share			Weighted Average Remaining Contractual Life (Years)		Number		Weighted Average Exercise Price per share
$  0.50 –   3.80		2,925,495		$	2.91		2.4		2,925,495		$	2.91
4.06 –   6.18		356,352			5.32		5.8		342,735			5.30
6.60 – 11.00		2,603,524			9.03		6.2		2,179,351			8.80
11.08 – 19.00		2,260,277			12.52		6.6		804,209			12.80

During the second quarter of 2004, and in connection with the recapitalization of the Company by PHAWK, LLC transaction, the Company issued PHAWK, LLC 5.0 million five-year common stock purchase warrants at a price of $3.30 per share. The warrants are exercisable at any time and expire on May 25, 2009. On August 31, 2005, 2.3 million warrants were exercised. The exercise was cashless, reducing number of shares issued by the value of the $3.30 exercise price, so that the Company issued 1.6 million shares of company stock. On July 8, 2005, shares and warrants held by PHAWK, LLC were distributed to its members, including certain members of our management. During the year ended December 31, 2007, 0.7 million warrants were exercised and a net 0.6 million shares of company stock were issued. These exercises were included within the options and warrants transactions table above.

Performance Shares

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

The fair value of the awards using a Monte Carlo technique was $10.89 per share. 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 $0.5 million and $0.3 million in compensation cost for the year ended December 31, 2007 and the period between the Company’s merger with KCS and December 31, 2006. At December 31, 2007, the unrecognized compensation expense related to non-vested performance shares totaled $0.6 million. During the year ended December 31, 2007, approximately 19,000 net shares of restricted stock were issued as a result of the termination of certain employees with the sale of the Company’s Gulf Coast properties.

2004 Employee Incentive Plan

Upon stockholder approval and effective July 28, 2005, the Company’s Amended and Restated 2004 Employee Incentive Plan was amended and restated to be the Second Amended and Restated 2004 Employee Incentive Plan to increase the aggregate number of shares that can be issued under the 2004 Employee Plan from 2.75 million to 4.25 million. The 2004 Plan permits the Company to grant to management and other employees shares of common stock with no restrictions, shares of common stock with restrictions, and options to purchase shares of common stock.

On July 12, 2006, the Company and its stockholders approved an amendment to the 2004 Plan Employee to increase the number of shares available for issuance thereunder from 4.25 million shares to 7.05 million shares.

 

71

---

Table of Contents

Index to Financial Statements

On July 18, 2007, the Company and its stockholders approved an amendment to the 2004 Employee Plan to increase the number of shares available for issuance thereunder from 7.05 million shares to 12.55 million shares.

In 2007, the Company granted a combination of stock appreciation rights and options covering 1.1 million shares of common stock to employees of the Company. The stock appreciation rights have exercise prices ranging from $11.64 to $18.69 with a weighted average price of $11.91. 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.

In 2006, the Company granted stock options covering 1.88 million shares of common stock to employees of the Company. The options have exercise prices ranging from $9.80 to $16.04 with a weighted average price of $11.94. These options vest over a three year period at a rate of one-third on the annual anniversary date of the grant and expire ten years from the grant date.

In connection with the Company’s merger with KCS, the Company converted legacy KCS stock options into a total of 2.6 million Petrohawk stock options on July 12, 2006. These options vest over a three-year period and expire ten years after the date of grant. Weighted average grant date fair value of the options was determined to be $9.81 per share, using the Black-Scholes fair value method. The Company recognized $0.9 million in compensation cost for the year ended December 31, 2006 and will recognize $1.2 million in future periods related to these options.

In 2005, the Company granted stock options covering 1.40 million shares of common stock to employees of the Company. The options vest over a three-year period with one-third vesting on the date of grant, one-third one year from the date of the grant and the remaining one-third two years from the date of the grant. The options have exercise prices ranging from $0.52 to $11.52 with a weighted average price of $9.37. These options expire ten years from the grant date.

At December 31, 2007, 7.4 million options were available under the 2004 Employee Plan for future issuance.

2004 Non-Employee Director Incentive Plan

In July 2004 the Company adopted the 2004 Non-Employee Director Plan covering 0.20 million shares. The plan provides for the grant of both incentive stock options and restricted shares of the Company’s stock. This plan was designed to attract and retain the services of directors. At the adoption of the plan, each non-employee director received 7,500 restricted shares of the Company’s common stock and each new non-employee director would receive 7,500 shares of the Company’s common stock. Additional grants of 5,000 restricted shares of the Company’s common stock were issued to each non-employee director on each anniversary of his or her service. Effective August 11, 2006, the annual equity grant to both new and existing non-employee directors increased to 10,000 shares of restricted stock. The vice chairman of the board of directors will receive 15,000 shares of restricted stock annually. These shares vest over a six month period from the date of grant. Shares were issued under this plan for the years ended December 31, 2007, 2006 and 2005, were 85,000 shares, 72,500 shares and 45,000 shares, respectively and there had been no forfeited or cancelled shares.

On July 12, 2006, the Company and its stockholders approved an amendment to the Company’s 2004 Non-Employee Director Plan to increase the number of shares available for issuance thereunder from 0.4 million to 0.6 million shares. At December 31, 2007, 0.32 million options were available under the Plan for future issuance.

At December 31, 2007, the unrecognized compensation expense related to non-vested non-employee directors was $0.2 million which will be recognized on a straight-line basis over the weighted average remaining vesting period of 0.1 years.

 

72

---

Table of Contents

Index to Financial Statements

KCS and Mission Incentive Plans

Upon consummation of the Company’s merger with KCS, the Company assumed the KCS 2001 Plan, as amended, the KCS 2005 Plan, as amended, and associated obligations relating to grants of restricted stock, stock options and performance shares under those plans which were granted prior to the closing of the Company’s merger with KCS. At December 31, 2007, no options were available under the Plan for future issuance.

In 2007, the Company granted stock appreciation rights covering 0.4 million shares of common stock to employees of the Company under the KCS 2005 Plan. The stock appreciation rights have an exercise price of $11.64 with a weighted average price of $11.64. These stock appreciation rights 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.

In conjunction with the Merger on July 28, 2005, the Company assumed three incentive plans related to Mission Resources. The three plans were the Mission 1994 Plan, Mission 1996 Plan and Mission 2004 Plan. At December 31, 2007, there were no options available under these plans for future issuance.

8% Cumulative Convertible Preferred Stock

On June 29, 2001 the Company completed its Private Placement Offering of 8% cumulative convertible preferred stock and common stock purchase warrants, offered as units of one preferred share and one-half of one warrant at $9.25 per unit. Net proceeds received from the offering were approximately $5.0 million net of estimated offering expenses, including brokers’ commissions and other fees and expenses of $0.5 million. The Company issued 0.6 million preferred shares and 0.15 million warrants to purchase a like number of shares of the Company’s common stock at a price equal to the offering price or $9.25 per share. Brokers were issued 29,888 non-callable warrants as part of their commission. All investors participating in the offering were accredited. The proceeds were used by the Company to help meet its capital requirements, including drilling costs and for other general corporate purposes.

In April 2006, the Company initiated a buyback of the preferred stock for $9.25 per unit. On June 9, 2006, the Company sent the holders of the preferred shares notice of redemption as set forth in the certificate of designation for the preferred stock. On July 10, 2006, the Company completed the redemption of the preferred stock. As of December 31, 2007, there were no remaining preferred shares outstanding. All Class A and Class B warrants associated with the preferred stock expired on June 29, 2006.

Treasury Stock

In August 2004, the Company’s Board of Directors terminated the stock repurchase program. During the quarter ended September 30, 2006, the Company retired its 8,382 treasury shares.

 

73

---

Table of Contents

Index to Financial Statements

Assumptions

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

 

		Years Ended December 31,
		2007 (1)(2)				2006				2005
Weighted average value per option granted during the period (3)		$	3.63			$	6.95			$	2.31
Assumptions (4):
Stock price volatility			38.0	%			39.0	%			29.3	%
Risk free rate of return			4.4	%			4.9	%			3.6	%
Expected term			3.0 years				2.9 years				3.0 years

 

(1)	Includes assumptions from valuation related to the Company’s merger with KCS.

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

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

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

9.     INCOME TAXES

Income tax (provision) benefit for the indicated periods is comprised of the following:

 

		Years Ended December 31,
		2007				2006				2005
		(in thousands)
Current:
Federal		$	(11,011	)		$	(2,069	)		$	(217	)
State			(998	)			(65	)			(253	)
			(12,009	)			(2,134	)			(470	)
Deferred:
Federal			(19,300	)			(66,337	)			9,088
State			(1,829	)			(4,064	)			445
			(21,129	)			(70,401	)			9,533
Total (provision) benefit		$	(33,138	)		$	(72,535	)		$	9,063

The actual income tax (provision) benefit differs from the expected income tax (provision) benefit as computed by applying the U.S. Federal corporate income tax rate of 35% for each period as follows:

 

		Years Ended December 31,
		2007				2006				2005
		(in thousands)
Amount of expected income tax (provision) benefit		$	(30,112	)		$	(66,184	)		$	8,994
State taxes, net			(1,385	)			(3,818	)			625
Valuation allowance			—				(191	)			(500	)
Other			(1,641	)			(2,342	)			(56	)
Total (provision) benefit		$	(33,138	)		$	(72,535	)		$	9,063

 

74

---

Table of Contents

Index to Financial Statements

The components of net deferred tax assets and liabilities recognized are as follows:

 

		December 31,
		2007				2006
		(in thousands)
Deferred current tax assets:
Unrealized hedging transactions		$	5,855			$	—
Deferred current tax assets		$	5,855			$	—
Deferred current tax liabilities:
Unrealized hedging transactions		$	—			$	(22,382	)
Deferred current tax liabilities		$	—			$	(22,382	)
Deferred noncurrent tax assets:
Net operating loss carry-forwards		$	125,215			$	112,175
Stock-based compensation expense			9,499				4,189
Unrealized hedging transactions			2,558				3,772
Alternative minimum tax credit carryforwards			18,438				7,368
Other operating property- equipment			—				—
Other			1,031				(2,312	)
Gross deferred noncurrent tax assets			156,741				125,192
Valuation allowance			(692	)			(692	)
Deferred noncurrent tax assets		$	156,049			$	124,500
Deferred noncurrent tax liabilities:
Book-tax differences in property basis		$	(831,017	)		$	(758,383	)
Unrealized hedging transactions			—				—
Deferred noncurrent tax liabilities		$	(831,017	)		$	(758,383	)
Net long-term deferred tax liabilities		$	(674,968	)		$	(633,883	)

Petrohawk adopted the provisions of FIN 48 effective January 1, 2007. FIN 48 prescribes a recognition threshold and a measurement attribute for the financial statement recognition and measurement of tax positions taken or expected to be taken in a tax return. For those benefits to be recognized, a tax position must be more-likely-than-not to be sustained upon examination by taxing authorities. There was not a material impact on the company’s operating results, financial position or cash flows as a result of the adoption of the provisions of FIN 48. A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:

 

		Liability for Unrecognized Tax Benefits
		(In thousands)
Balance at January 1, 2007		$	2,100
Additions for Tax Positions of Prior Years			1,260
Reductions for Tax Positions of Prior Years			(274	)
Lapse of Statute of Limitations			—
Balance at December 31, 2007		$	3,086

Generally, the Company’s tax years 2004 through 2007 remain open and subject to examination by Federal tax authorities or the tax authorities in Arkansas, Louisiana, New Mexico, Oklahoma and Texas which are the jurisdictions where Petrohawk has its principal operations. In certain jurisdictions the Company operates through more than one legal entity, each of which may have different open years subject to examination. The Company has been notified by the Internal Revenue Service of its intent to commence, during the first quarter of 2008, an examination of the Federal return filed by KCS Energy Inc. for the tax year ending December 31, 2005. No

 

75

---

Table of Contents

Index to Financial Statements

material amounts of the unrecognized tax benefits have been identified to date that would impact the Company’s effective tax rate.

Petrohawk recognizes interest and penalties accrued to unrecognized benefits in interest expense and other in its statement of operations. During 2007 Petrohawk recognized $0.1 million in interest and penalties. The Company had approximately $0.2 million and $0.1 million for the payment of interest and penalties accrued as December 31, 2007 and 2006, respectively.

As of December 31, 2007, the Company had available, to reduce future taxable income, a U.S. federal regular net operating loss (NOL) carryforward of approximately $350.3 million (net of excess tax benefits not recognized), which expire in the years 2017 through 2025. Utilization of NOL carryforwards is subject to annual limitations due to stock ownership changes. The tax net operating loss carryforward may be limited by other factors as well. The Company also has various state NOL carryforwards, reduced by the valuation allowance for losses that the Company anticipates will expire before they can be utilized, totaling approximately $160.6 million at December 31, 2007, with varying lengths of allowable carryforward periods ranging from five to 20 years that can be used to offset future state taxable income. It is expected that these deferred tax benefits will be utilized prior to their expiration.

10.     RELATED PARTY TRANSACTIONS

On May 25, 2004, PHAWK, LLC (formerly known as Petrohawk Energy, LLC) (PHAWK), which was owned by affiliates of EnCap Investments, L.P., Liberty Energy Holdings LLC, Floyd C. Wilson and other members of the Company’s management, purchased a controlling interest in the Company for $60 million in cash. The $60 million investment was structured as the purchase by PHAWK of 7.576 million shares of common stock for $25 million, a $35 million five year 8% subordinated note convertible into approximately 8.75 million shares of common stock and warrants to purchase 5 million shares of common stock at a price of $3.30 per share (after giving effect to a one-for-two reverse split of the Company’s common stock implemented in May 2004). In connection with the investment by PHAWK, Mr. Wilson was named Chairman, President and Chief Executive Officer, the Company’s board of directors and other management was changed, and the corporate offices were relocated from Tulsa, Oklahoma to Houston, Texas. Also, at the annual stockholders meeting held July 15, 2004, the Company’s stockholders approved changing the name of the company to Petrohawk Energy Corporation (from Beta Oil & Gas, Inc.), reincorporating the company in Delaware, and the adoption of new stock option plans.

On June 30, 2005, the Company entered into an agreement with PHAWK to convert the Company’s $35 million note payable to PHAWK to common stock as stipulated in the original agreement. The original agreement contained a provision providing for conversion into 8.75 million shares of Petrohawk common stock at any time after May 25, 2006. In consideration of the early conversion, the Company agreed to make a payment of $2.4 million, which represented the interest payable on the note through May 25, 2006, discounted at 10%. In conjunction with the conversion, the Company expensed $1.1 million of net debt issuance costs that were being amortized over the remaining life of the note. These charges are reflected in interest expense and other on the consolidated statement of operations.

A Special Committee of one disinterested director was formed by the Company’s board of directors to evaluate the transaction. On June 30, 2005, the Special Committee approved the transaction.

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

 

76

---

Table of Contents

Index to Financial Statements

11.	NET INCOME (LOSS) PER COMMON SHARE

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

 

		Years Ended December 31,
		2007			2006				2005
		(In thousands, except per share amounts)
Basic
Net income (loss)		$	52,897		$	116,563			$	(16,634	)
Less: preferred dividends			—			(217	)			(440	)
Net income (loss) available to common stockholders		$	52,897		$	116,346			$	(17,074	)
Weighted average basic number of shares outstanding			168,006			122,452				54,752
Basic earnings (loss) per share		$	0.31		$	0.95			$	(0.31	)
Diluted
Net income (loss)		$	52,897		$	116,346			$	(17,074	)
Plus: preferred dividends			—			217				—
Net income (loss) available to common stockholders		$	52,897		$	116,563			$	(17,074	)
Weighted average number of shares			168,006			122,452				54,752
Common stock equivalent shares representing shares issuable upon exercise of stock options			1,406			989				Anti-dilutive
Common stock equivalent shares representing shares issuable upon exercise of warrants			971			1,251				Anti-dilutive
Common stock equivalent shares representing shares included upon vesting of restricted shares			865			1,443				Anti-dilutive
Common stock equivalent shares representing shares “as-if” conversion of note payable			—			—				Anti-dilutive
Common stock equivalent shares representing shares “as-if” conversion of preferred shares			—			—				Anti-dilutive
Weighted average diluted number of shares outstanding			171,248			126,135				54,752
Diluted earnings (loss) per share		$	0.31		$	0.92			$	(0.31	)

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

 

		Years Ended December 31,
Common Stock Equivalents:		2007		2006		2005
		(In thousands)
Options and stock appreciation rights		54		894		2,779
Warrants		—		18		2,919
“As-if” conversion of Preferred stock		—		—		294
		54		912		5,992

 

77

---

Table of Contents

Index to Financial Statements

12.	ADDITIONAL FINANCIAL STATEMENT INFORMATION

Certain balance sheet amounts are comprised of the following:

 

		December 31,
		2007			2006
		(In thousands)
Accounts receivable:
Oil and gas sales		$	77,033		$	107,003
Joint interest accounts			52,210			37,056
Income taxes receivable			1,788			5,453
Advances receivable			15,906			—
Other			1,201			6,070
		$	148,138		$	155,582
Prepaids expenses and other:
Prepaid insurance		$	2,690		$	3,333
Prepaid drilling costs			13,937			10,854
Other			4,392			3,116
		$	21,019		$	17,303
Accounts payable and accrued liabilities:
Trade payables		$	25,751		$	31,565
Revenues and royalties payable			90,967			69,383
Accrued capital costs			117,748			111,252
Accrued interest expense			37,557			40,906
Other prepayment liabilities			10,977			5,839
Accrued lease operating expenses			6,373			10,601
Accrued ad valorem taxes payable			5,578			7,086
Accrued employee compensation			3,468			2,649
Other			33,052			16,670
		$	331,471		$	295,951

Certain cash and non-cash related items:

 

		Years Ended December 31,
		2007				2006			2005
		(In thousands)
Cash payments:
Interest payments		$	128,769			$	43,714		$	26,507
Income tax payments (refunds)			(931	)			4,847			24
Non-cash items excluded from the statement of cash flows:
Accrued capital expenditures			6,496				87,642			6,005

 

13.	SUBSEQUENT EVENTS

As of February 25, 2008, the Company had received a waiver for the current ratio requirement under its senior revolving credit facility as of December 31, 2007. Refer to Note 4, “Long-term Debt” for more details.

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. These properties include interests primarily in Van Buren and Cleburne Counties, Arkansas. These properties are substantially undeveloped. The transaction closed on February 8, 2008.

 

78

---

Table of Contents

Index to Financial Statements

Effective February 5, 2008, the Company entered into the Fifth Amendment (the 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. Pursuant to the Fifth Amendment, the Company’s borrowing base under the senior revolving credit facility was increased from $675 million to $1 billion, inclusive of a $100 million component set to expire effective February 5, 2009. Borrowings above $900 million will carry applicable LIBOR and ABR margins of 2.00% and 0.750%, respectively. The Fifth Amendment included a waiver beginning December 31, 2007 for 2008 of the limit set forth in the Credit Agreement on commodity swap 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 70% of anticipated total forecasted oil or natural gas production for each month during 2008.

On January 29, 2008, the Company entered into an underwriting agreement (the Underwriting Agreement), pursuant to which the Company sold an aggregate of 18,000,000 shares of its common stock, $0.001 par value (the Common Stock) to the several underwriters named in the Underwriting Agreement (the Underwriters). 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 Company was notified that the Underwriters have exercised in full their option to purchase additional shares of Common Stock. These transactions closed on February 1, 2008. The net proceeds from the sale of the Common Stock sold (including Common Shares sold pursuant to the Underwriters’ over-allotment option) were approximately $297.3 million (after deducting underwriting discounts and commissions and estimated expenses).

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 a purchase price of approximately $169 million.

In June 2007, Petrohawk announced its intention to form a publicly-traded master limited partnership, HK Energy Partners LP, or the MLP, which would initially acquire certain of Petrohawk’s oil and natural gas properties located in West Texas, New Mexico and Oklahoma. On October 30, 2007, Petrohawk filed a Form S-1 with the Securities and Exchange Commission to form this MLP. The Company anticipates that the MLP will offer approximately $150 million to $225 million of partnership units to the public, subject to regulatory processes and market conditions. At the closing of the initial public offering, Petrohawk would be the general partner of the MLP and hold a majority ownership in the units of the MLP. Petrohawk would continue to operate and own a working interest in certain of the assets that would form the MLP. On January 25, 2008, due to current market conditions, the Company announced that it has delayed its proposed initial public offering.

 

79

---

Table of Contents

Index to Financial Statements

SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)

Oil and Natural Gas Reserves

Users of this information should be aware that the process of estimating quantities of proved and proved developed oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various reservoirs make these estimates generally less precise than other estimates included in the financial statement disclosures.

Proved reserves represent estimated quantities of natural gas, crude oil and condensate that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions in effect when the estimates were made. Proved developed reserves are proved reserves expected to be recovered through wells and equipment in place and under operating methods used when the estimates were made.

Estimates of proved reserves at December 31, 2007, 2006 and 2005 were prepared by Netherland, Sewell & Associates, Inc. (Netherland, Sewell), the Company’s independent consulting petroleum engineers. All proved reserves are located in the United States of America.

The following table illustrates the Company’s estimated net proved reserves, including changes, and proved developed reserves for the periods indicated, as estimated by Netherland, Sewell. Natural gas liquids are included in natural gas reserves. Oil and natural gas liquids are based on the December 31, 2007 West Texas Intermediate posted price of $92.50 per barrel, and posted price of $57.75 per barrel on December 31, 2006 and 2005 which are adjusted by lease for quality, transportation fees, and regional price differentials. Gas prices are based on a December 31, 2007, 2006 and 2005 Henry Hub spot market price of $6.80 per MMbtu, $5.63 per MMbtu and $10.08 per MMbtu and are adjusted by lease for energy content, transportation fees, and regional price differentials. All prices are held constant in accordance with SEC guidelines.

 

		Proved Reserves
		Oil (MBbls)			Gas (MMcf)			Equivalent (MMcfe)
Proved reserves, December 31, 2004		9,701			160,878			219,084
Extensions and discoveries		1,409			19,905			28,359
Purchase of minerals in place		12,520			157,669			232,789
Production		(1,555	)		(20,219	)		(29,549	)
Sale of minerals in place		(2,723	)		(12,670	)		(29,008	)
Revision of previous estimates		2,115			2,904			15,594
Proved reserves, December 31, 2005		21,467			308,467			437,269
Extensions and discoveries		4,109			270,526			295,180
Purchase of minerals in place		8,597			485,270			536,852
Production		(2,703	)		(63,645	)		(79,863	)
Sale of minerals in place		(6,528	)		(40,653	)		(79,821	)
Revisions of previous estimates		(531	)		(30,311	)		(33,497	)
Proved reserves, December 31, 2006		24,411			929,654			1,076,120
Extensions and discoveries (1)		4,912			296,816			326,288
Purchase of minerals in place		184			42,587			43,691
Production		(2,816	)		(99,506	)		(116,402	)
Sale of minerals in place		(11,553	)		(204,093	)		(273,411	)
Revisions of previous estimates		2,601			(10,305	)		5,301
Proved reserves, December 31, 2007		17,739			955,153			1,061,587

 

(1)	Includes infill reserves extensions in existing proved fields of 232,065 MMcfe.

 

80

---

Table of Contents

Index to Financial Statements

		Proved Developed Reserves
		Oil (Mbls)		Gas (MMcf)		Equivalent (MMcfe)
December 31, 2005		17,118		209,282		311,990
December 31, 2006		17,944		566,024		673,688
December 31, 2007		12,142		533,902		606,754

Capitalized Costs Relating to Oil and Natural Gas Producing Activities

The following table illustrates the total amount of capitalized costs relating to oil and natural gas producing activities and the total amount of related accumulated depreciation, depletion and amortization (in thousands).

 

		December 31,
		2007				2006				2005
Evaluated properties		$	3,249,484			$	2,903,763			$	1,098,553
Unevaluated properties			677,565				537,611				162,133
			3,927,049				3,441,374				1,260,686
Accumulated depreciation, depletion and amortization			(770,288	)			(379,984	)			(122,301	)
		$	3,156,761			$	3,061,390			$	1,138,385

Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities

Costs incurred in property acquisition, exploration and development activities were as follows (in thousands):

 

		Years Ended December 31,
		2007			2006			2005
Property acquisition costs, proved		$	165,614		$	1,406,489		$	600,972
Property acquisition costs, unproved			356,348			517,695			107,664
Exploration and extension well costs			372,438			337,076			35,083
Development costs			379,749			152,335			67,912
Total costs		$	1,274,149		$	2,413,595		$	811,631

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves

The following information has been developed utilizing SFAS 69, Disclosures about Oil and Gas Producing Activities, (SFAS 69) procedures and based on oil and natural gas reserve and production volumes estimated by the Company’s engineering staff. It can be used for some comparisons, but should not be the only method used to evaluate the Company or its performance. Further, the information in the following table may not represent realistic assessments of future cash flows, nor should the Standardized Measure of Discounted Future Net Cash Flow be viewed as representative of the current value of the Company.

The Company believes that the following factors should be taken into account when reviewing the following information:

 

•

future costs and selling prices will probably differ from those required to be used in these calculations;

 

•

due to future market conditions and governmental regulations, actual rates of production in future years may vary significantly from the rate of production assumed in the calculations;

 

•

a 10% discount rate may not be reasonable as a measure of the relative risk inherent in realizing future net oil and natural gas revenues; and

 

•

future net revenues may be subject to different rates of income taxation.

 

81

---

Table of Contents

Index to Financial Statements

Under the Standardized Measure, future cash inflows were estimated by applying year-end oil and natural gas prices to the estimated future production of year-end proved reserves. Estimates of future income taxes are computed using current statutory income tax rates including consideration for estimated future statutory depletion and tax credits. The resulting net cash flows are reduced to present value amounts by applying a 10% discount factor. Use of a 10% discount rate and year-end prices are required by SFAS 69.

The Standardized Measure is as follows (in thousands):

 

		Years Ended December 31,
		2007				2006				2005
Future cash inflows		$	8,434,767			$	6,492,900			$	3,636,669
Future production costs			(2,004,206	)			(1,703,787	)			(988,796	)
Future development costs			(1,227,874	)			(1,044,147	)			(255,800	)
Future income tax expense			(1,549,136	)			(1,004,896	)			(669,018	)
Future net cash flows before 10% discount			3,653,551				2,740,070				1,723,055
10% annual discount for estimated timing of cash flows			(1,728,055	)			(1,170,023	)			(699,336	)
Standardized measure of discounted future net cash flows		$	1,925,496			$	1,570,047			$	1,023,719

Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves

The following is a summary of the changes in the Standardized Measure of discounted future net cash flows for the Company’s proved oil and natural gas reserves during each of the years in the three year period ended December 31, 2007 (in thousands).

 

		Years Ended December 31,
		2007				2006				2005
Beginning of year		$	1,570,047			$	1,023,719			$	412,870
Sale of oil and gas produced, net of production costs			(719,677	)			(459,881	)			(203,463	)
Purchase of minerals in place			84,889				1,484,511				695,811
Sales of minerals in place			(903,165	)			(265,315	)			(71,585	)
Extensions and discoveries			708,563				353,392				148,154
Changes in income taxes, net			(188,388	)			(84,094	)			(288,240	)
Changes in prices and costs			817,610				(791,504	)			150,245
Development costs incurred			379,749				152,335				67,912
Revisions of previous quantities			12,855				(48,142	)			53,179
Accretion of discount			198,275				225,683				79,868
Changes in production rates and other			(35,262	)			(20,657	)			(21,032	)
End of year		$	1,925,496			$	1,570,047			$	1,023,719

 

82

---

Table of Contents

Index to Financial Statements

SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)

The following table presents selected quarterly financial data derived from the Company’s consolidated financial statements. The following data is only a summary and should be read with the Company’s historical consolidated financial statements and related notes contained in this document. The acquisition of KCS in 2006 and Mission in 2005 affects the comparability between the consolidated financial data for the periods presented.

 

		Quarters Ended
		March 31				June 30				September 30				December 31
		(In thousands, except per share amounts)
2007
Oil and gas sales		$	209,243			$	233,482			$	213,337			$	227,343
Income from operations			58,677				72,804				55,931				63,237
Net (loss) income (1)			(19,415	)			45,631				26,795				(114	)
(Loss) earnings per share of common stock:
Basic		$	(0.12	)		$	0.27			$	0.16			$	0.00
Diluted		$	(0.12	)		$	0.27			$	0.16			$	0.00
2006
Oil and gas sales		$	103,006			$	86,414			$	196,439			$	201,903
Income from operations			36,430				18,364				50,691				49,055
Net income (1)			32,939				4,853				52,656				26,115
Earnings per share of common stock:
Basic		$	0.40			$	0.06			$	0.34			$	0.16
Diluted		$	0.39			$	0.06			$	0.33			$	0.15
2005
Oil and gas sales		$	32,326			$	36,184			$	81,447			$	108,082
Income from operations			9,030				11,427				34,018				49,415
Net (loss) income (1)			(14,252	)			(2,202	)			(36,424	)			36,244
(Loss) earnings per share of common stock:
Basic		$	(0.36	)		$	(0.06	)		$	(0.56	)		$	0.49
Diluted		$	(0.36	)		$	(0.06	)		$	(0.56	)		$	0.48

 

(1)	The volatility in net income (loss) is substantially due to the Company’s accounting policy to mark derivative positions to market and not apply cash flow hedge accounting. See Note 7, “Derivative and Hedging Activities” for additional information.

 

83

---

Table of Contents

Index to Financial Statements

ITEM 9.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

 

ITEM 9A.

CONTROLS AND PROCEDURES

Management’s Evaluation of Disclosure 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 December 31, 2007 to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms. Our disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

Management’s Report on Internal Control over Financial Reporting

Management’s report on internal control over financial reporting as of December 31, 2007 can be found on page 44 of the Financial Section of this report.

Changes in Internal Control over Financial Reporting

There has been no change in our internal control over financial reporting that occurred during the three months ended December 31, 2007 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

 

ITEM 9B.

OTHER INFORMATION

None.

 

84

---

Table of Contents

Index to Financial Statements

PART III

 

ITEM 10.

DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

The information required to be contained in this Item is incorporated by reference to our definitive proxy statement to be filed with respect to our 2008 annual meeting under the heading Directors, Executive Officers and Corporate Governance.

 

ITEM 11.

EXECUTIVE COMPENSATION

The information required to be contained in this Item is incorporated by reference to our definitive proxy statement to be filed with respect to our 2008 annual meeting under the heading Executive Compensation.

 

ITEM 12.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

The information required to be contained in this Item is incorporated by reference to our definitive proxy statement to be filed with respect to our 2008 annual meeting under the heading Principal Stockholders and Security Ownership of Management and Related Stockholder Matters.

 

ITEM 13.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

The information required to be contained in this Item is incorporated by reference to our definitive proxy statement to be filed with respect to our 2008 annual meeting under the heading Certain Transactions.

 

ITEM 14.

PRINCIPAL ACCOUNTANT FEES AND SERVICES

The information required to be contained in this Item is incorporated by reference to our definitive proxy statement to be filed with respect to our 2008 annual meeting under the heading Ratification of Appointments of Independent Auditors.

 

85

---

Table of Contents

Index to Financial Statements

PART IV

 

ITEM 15.

EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

 

(1)	Consolidated Financial Statements:

The consolidated financial statements of the Company and its subsidiaries and report of independent registered public accounting firm listed in Section 8 of this Form 10-K are filed as a part of this Form 10-K.

 

(2)	Consolidated Financial Statements Schedules:

All schedules are omitted because they are inapplicable or because the required information is contained in the financial statements or included in the notes thereto.

 

(3)

Exhibits:

The following documents are included as exhibits to this Form 10-K.

 

Exhibit No.		Description
1.1		Underwriting Agreement, dated January 29, 2008, among the Company and Lehman Brothers Inc. and Merrill Lynch, Pierce, Fenner & Smith Incorporated, on behalf of Lehman Brothers Inc., Merrill Lynch, Pierce, Fenner & Smith Incorporated, J.P. Morgan Securities Inc., BMO Capital Markets Corp., RBC Capital Markets Corporation, Jefferies & Company, Inc., BNP Paribas Securities Corp., Tristone Capital (U.S.A.) Inc. and Friedman, Billings, Ramsey & Co., Inc. (Incorporated by reference to Exhibit 1.1 of our Current Report on Form 8-K filed February 1, 2008).
2.1		Agreement and Plan of Merger, dated April 3, 2005 (and as amended through June 8, 2005), by and among Petrohawk Energy Corporation, Petrohawk Acquisition Corporation, and Mission Resources Corporation (Incorporated by reference to Annex A of our Registration Statement on Form S-4/A filed on June 22, 2005).
2.2		Agreement and Plan of Merger, dated October 13, 2004, among Petrohawk Energy Corporation, Wynn-Crosby Energy, Inc., Ronald W. Crosby and Paige L. Crosby (Incorporated by reference to Exhibit 2.1 of our Current Report on Form 8-K filed on November 24, 2004).
2.3		Agreement and Plan of Mergers, dated October 13, 2004, among Petrohawk Energy Corporation, Wynn-Crosby Energy, Inc., Wynn-Crosby 1994, Ltd.; Wynn-Crosby 1995, Ltd.; Wynn-Crosby 1996, Ltd.; Wynn-Crosby 1997, Ltd.; Wynn-Crosby 1998, Ltd.; Wynn-Crosby 1999, Ltd.; Wynn-Crosby 2000, Ltd.; Wynn-Crosby 2002, Ltd.; WCOG Properties, Ltd.; Kara Nicole Limited; Kristen Lee Limited; Eric Wynn Limited; Christopher David Limited; Paige Lee Limited; Bernadien Wynn Limited; Roger Lee Limited; and George Heaps Limited, and Ronald W. Crosby (Incorporated by reference to Exhibit 2.2 of our Current Report on Form 8-K filed on November 24, 2004).
2.4		Amendment to Agreement and Plan of Mergers among Petrohawk Energy Corporation, Wynn-Crosby Energy, Inc., Wynn-Crosby 1994, Ltd.; Wynn-Crosby 1995, Ltd.; Wynn-Crosby 1996, Ltd.; Wynn-Crosby 1997, Ltd.; Wynn-Crosby 1998, Ltd.; Wynn-Crosby 1999, Ltd.; Wynn-Crosby 2000, Ltd.; Wynn-Crosby 2002, Ltd.; WCOG Properties, Ltd.; Kara Nicole Limited; Kristen Lee Limited; Eric Wynn Limited; Christopher David Limited; Paige Lee Limited; Bernadien Wynn Limited; Roger Lee Limited; and George Heaps Limited, and Ronald W. Crosby, dated October 26, 2004 (Incorporated by reference to Exhibit 2.3 of our Current Report on Form 8-K filed on November 24, 2004).
2.5		Stock Purchase Agreement among Winwell Resources, Inc. and all of its Shareholders, as Sellers, and Petrohawk Energy Corporation, as Buyer, dated as of December 14, 2005 (Incorporated by reference to Exhibit 2.1 of our Current Report on Form 8-K filed December 20, 2005).

 

86

---

Table of Contents

Index to Financial Statements

Exhibit No.		Description
2.6		Asset Purchase Agreement among Redley Company, Burris Run Company and Red Clay Minerals, collectively as Seller, and Petrohawk Energy Corporation, as Buyer, dated as of December 14, 2005 (Incorporated by reference to Exhibit 2.2 of our Current Report on Form 8-K filed December 20, 2005).
2.7		First Amendment to Asset Purchase Agreement among Redley Company, Burris Run Company and Red Clay Minerals, collectively as Seller, and Petrohawk Energy Corporation, as Buyer, effective as of December 14, 2005 (Incorporated by reference to Exhibit 2.7 of our Annual Report on Form 10-K filed March 14, 2006).
2.8		Assignment Agreement between Petrohawk Properties, L.P. and Petrohawk Energy Corporation effective January 27, 2006 (Incorporated by reference to Exhibit 2.8 of our Annual Report on Form 10-K filed March 14, 2006).
2.9		Purchase and Sale Agreement executed January 14, 2005, by and between Wynn-Crosby 1994, Ltd., et al and Noble Royalties, Inc. d/b/a Brown Drake Royalties (Incorporated by reference to Exhibit 2.1 to our Current Report on Form 8-K filed on March 3, 2005).
2.10		Amendment to Purchase and Sale Agreement executed on February 15, 2005, by and between Wynn-Crosby 1994, Ltd., et al and Noble Royalty, Inc. d/b/a Brown Drake Royalties (Incorporated by reference to Exhibit 2.2 to our Current Report on Form 8-K filed on March 3, 2005).
2.11		Stock Purchase Agreement dated February 4, 2005 by and among Petrohawk Energy Corporation and Proton Oil & Gas Corporation, et al (Incorporated by reference to Exhibit 2.3 to our Current Report on Form 8-K filed on March 3, 2005).
2.12		Purchase and Sale Agreement between Petrohawk Energy Corporation and Petrohawk Properties, LP, together, as Seller, and Northstar GOM, LLC, as Buyer, dated February 3, 2006 (Incorporated by reference to Exhibit 2.1 to our Current Report on Form 8-K filed February 9, 2006).
2.13		Amended and Restated Agreement and Plan of Merger executed as of May 16, 2006, and effective as of April 20, 2006 by and among KCS Energy, Inc., Petrohawk Energy Corporation and Hawk Nest Corporation (Incorporated by reference to Exhibit 2.1 of our Current Report on Form 8-K filed May 18, 2006).
3.1		Certificate of Incorporation for Petrohawk Energy Corporation (Incorporated by reference to Exhibit 3.1 to our Form S-8 (File No. 333-117733) filed on July 29, 2004).
3.2		Certificate of Amendment to Certificate of Incorporation for Petrohawk Energy Corporation (Incorporated by reference to Exhibit 3.1 of our Current Report on Form 8-K filed on November 24, 2004).
3.3		Certificate of Amendment of Certificate of Incorporation of Petrohawk Energy Corporation (Incorporated by reference to Exhibit 3.1 of our Current Report on Form 8-K filed on August 3, 2005).
3.4		Amended and Restated Bylaws of Petrohawk Energy Corporation effective as of July 12, 2006 (Incorporated by reference to Exhibit 3.2 of our Current Report on Form 8-K filed on July 17, 2006).
3.5		Certificate of Amendment to Certificate of Incorporation of Petrohawk Energy Corporation (Incorporated by reference to Exhibit 3.1 of our Current Report on Form 8-K filed on July 17, 2006).
4.1		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 7 1/8 % 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.)

 

87

---

Table of Contents

Index to Financial Statements

Exhibit No.		Description
4.2		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.)
4.3		Second Supplemental Indenture dated July 12, 2006 among Petrohawk Energy Corporation, the successor by way of merger to KCS Energy, Inc., the parties named therein as guarantors, and U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit 4.4 to our Current Report on Form 8-K filed July 17, 2006).
4.4		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).
4.5		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 9 1/8 % senior notes due 2013 (Incorporated by reference to Exhibit 4.6 to our Current Report on Form 8-K filed July 17, 2006).
4.6		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).
4.7		Registration Rights Agreement dated July 12, 2006 among Petrohawk Energy Corporation, the Guarantors named therein, and the Initial Purchasers named therein (Incorporated by reference to Exhibit 4.3 to our Registration Statement on Form S-4 filed September 1, 2006).
4.8		Registration Rights Agreement dated July 12, 2006 among Petrohawk Energy Corporation, the Guarantors named therein, and the Initial Purchasers named therein (Incorporated by reference to Exhibit 4.4 to our Registration Statement on Form S-4 filed September 1, 2006).
4.9		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 of our Quarterly Report on Form 10-Q filed November 8, 2007).
10.1†		The Petrohawk Energy Corporation Amended and Restated 1999 Incentive and Nonstatutory Stock Option Plan (Incorporated by reference to Exhibit 99.3 of our Current Report on Form 8-K filed on August 18, 2004).
10.2†		The Petrohawk Energy Corporation Second Amended and Restated 2004 Non-Employee Director Incentive Plan (Incorporated by reference to Exhibit 4.1 to our Registration Statement No. 333-117733 on Form S-8 filed July 29, 2005).
10.3†		Form of Stock Option Agreement for the Second Amended and Restated 2004 Non-Employee Director Incentive Plan (Incorporated by reference to Exhibit 10.3 to our Quarterly Report on Form 10-Q filed August 11, 2005).
10.4†		Form of Restricted Stock Agreement for the Second Amended and Restated 2004 Non-Employee Director Incentive Plan (Incorporated by reference to Exhibit 10.4 of our Second Quarter 2005 Form 10-Q filed on August 11, 2005).
10.5†		Form of Incentive Stock Agreement for the Second Amended and Restated 2004 Non-Employee Director Incentive Plan (Incorporated by reference to Exhibit 10.5 of our Second Quarter 2005 Form 10-Q filed on August 11, 2005).

 

88

---

Table of Contents

Index to Financial Statements

Exhibit No.		Description
10.6†		The Petrohawk Energy Corporation Second Amended and Restated 2004 Employee Incentive Plan (Incorporated by reference to Exhibit 4.2 to our Registration Statement No. 333-117733 on Form S-8 filed July 29, 2005).
10.7†		Form of Stock Option Agreement for the Second Amended and Restated 2004 Employee Incentive Plan (Incorporated by reference to Exhibit 10.3 of our Annual Report on Form 10-K filed March 14, 2006).
10.8†		Form of Restricted Stock Agreement for the Second Amended and Restated 2004 Employee Incentive Plan (Incorporated by reference to Exhibit 10.8 of our Second Quarter 2005 Form 10-Q filed on August 11, 2005).
10.9†		Form of Incentive Stock Agreement for the Second Amended and Restated 2004 Employee Incentive Plan (Incorporated by reference to Exhibit 10.9 of our Second Quarter 2005 Form 10-Q filed on August 11, 2005).
10.10†		Mission Resources Corporation 1994 Stock Incentive Plan (Incorporated by reference to Exhibit 10.9 of Mission Resources Corporation’s Registration Statement No. 33-76570 filed on March 17, 1994).
10.11†		Mission Resources Corporation 1996 Stock Incentive Plan (Incorporated by reference to Exhibit A of Mission Resources Corporation’s Proxy Statement on Schedule 14A filed on October 21, 1996).
10.12†		Mission Resources Corporation 2004 Incentive Plan (Incorporated by reference to Appendix C to Mission Resources Corporation’s Proxy Statement on Schedule 14A filed on March 30, 2004).
10.13†		Form of Director and Officer Indemnity Agreement (Incorporated by reference to Exhibit 10.11 of our Annual Report on Form 10-K filed on March 31, 2005).
10.14		Second Amended and Restated Senior Revolving Credit Agreement dated July 12, 2006, among Petrohawk Energy Corporation, each of the Lenders from time to time party thereto, BNP Paribas, as administrative agent for the lenders, Bank of America, N.A. and BMO Capital Markets Financing, Inc., as co-syndication agents for the Lenders, and JPMorgan Chase Bank, N.A., Wells Fargo Bank, N.A. and Fortis Capital Corp., as co-documentation agents for the Lenders (Incorporated by reference to Exhibit 10.3 to our Current Report on Form 8-K filed July 17, 2006).
10.15		Amended and Restated Guarantee and Collateral Agreement dated July 12, 2006, made by Petrohawk Energy Corporation and each of its subsidiaries, as Grantors, in favor of BNP Paribas, as Administrative Agent (Incorporated by reference to Exhibit 10.4 to our Current Report on Form 8-K filed July 17, 2006).
10.16		First Amendment to Second Amended and Restated Senior Revolving Credit Agreement, dated as of July 12, 2006, between Petrohawk Energy Corporation, each of the lenders from time to time party thereto, BNP Paribas, as administrative agent for the lenders, Bank of America, N.A. and BMO Capital Markets Financing, Inc. as co-syndication agents for the lenders, and JPMorgan Chase Bank, N.A., Wells Fargo Bank, N.A. and Fortis Capital Corp. as co-documentation agents for the lenders (Incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed July 28, 2006).
10.17†		First Amendment to the Petrohawk Energy Corporation Second Amended and Restated 2004 Employee Incentive Plan (Incorporated by reference to Exhibit 10.7 to our Quarterly Report on Form 10-Q filed August 9, 2006).
10.18†		First Amendment to the Petrohawk Energy Corporation Second Amended and Restated 2004 Non-Employee Director Incentive Plan (Incorporated by reference to Exhibit 10.8 to our Quarterly Report on Form 10-Q filed August 9, 2006).

 

89

---

Table of Contents

Index to Financial Statements

Exhibit No.		Description
10.19†		KCS Energy, Inc. 2001 Employee and Directors Stock Plan (Incorporated by reference to Exhibit (10)iii to KCS Energy, Inc.’s Annual Report on Form 10-K filed April 2, 2001), as amended by the Amendment to the KCS Energy, Inc. 2001 Employee and Directors Stock Plan (Incorporated by reference to Exhibit 10.4 to KCS Energy, Inc.’s Current Report on Form 8-K filed April 25, 2006).
10.20†		Form of Supplemental Stock Option Agreement under KCS Energy, Inc. 2001 Employee and Directors Stock Plan (Incorporated by reference to Exhibit 10.6 of KCS Energy, Inc’s Quarterly Report on Form 10-Q filed November 9, 2004).
10.21†		Form of Directors Supplemental Stock Option Agreement under KCS Energy, Inc. 2001 Employee and Directors Stock Plan (Incorporated by reference to Exhibit 10.7 of KCS Energy, Inc.’s Quarterly Report on Form 10-Q filed November 9, 2004).
10.22†		Form of Restricted Stock Award Agreement under KCS Energy, Inc. 2001 Employee and Directors Stock Plan (Incorporated by reference to Exhibit 10.8 of KCS Energy, Inc.’s Quarterly Report on Form 10-Q filed November 9, 2004).
10.23†		Form of Restricted Stock Award Agreement (with accelerated vesting provision) under 2001 KCS Energy, Inc. Employee and Directors Stock Plan (Incorporated by reference to Exhibit 10.9 of KCS Energy, Inc.’s Quarterly Report on Form 10-Q filed November 9, 2004).
10.24†		KCS Energy, Inc. 2005 Employee and Directors Stock Plan (Incorporated by reference to Exhibit 4.8 to KCS Energy, Inc’s Registration Statement on Form S-8 (File No. 333-125690) filed June 10, 2005), as amended by the First Amendment to KCS Energy, Inc. 2005 Employee and Directors Stock Plan (Incorporated by reference to Exhibit 10.1 to KCS Energy, Inc.’s Current Report on Form 8-K filed May 19, 2005).
10.25†		Form of Supplemental Stock Option Agreement under KCS Energy, Inc. 2005 Employee and Directors Stock Plan and related Stock Option Exercise Agreement (Incorporated by reference to Exhibit 10.3 of KCS Energy, Inc.’s Current Report on Form 8-K filed June 16, 2005).
10.26†		Form of Supplemental Stock Option Agreement for Non-Employee Directors under KCS Energy, Inc. 2005 Employee and Directors Stock Plan (Incorporated by reference to Exhibit 10.4 of KCS Energy, Inc’s Current Report on Form 8-K filed June 16, 2005).
10.27†		Form of Restricted Stock Award Agreement under KCS Energy, Inc. 2005 Employee and Directors Stock Plan (without accelerated vesting provision) and related Restricted Stock Award Certificate (Incorporated by reference to Exhibit 10.5 of KCS Energy, Inc’s Current Report on Form 8-K filed June 16, 2005).
10.28†		Form of Restricted Stock Award Agreement under KCS Energy, Inc. 2005 Employee and Directors Stock Plan (with accelerated vesting provision) and related Restricted Stock Award Certificate (Incorporated by reference to Exhibit 10.6 of KCS Energy, Inc.’s Current Report on Form 8-K filed June 16, 2005).
10.29†		Form of Amended and Restated Performance Share Award Certificate under KCS Energy, Inc. 2005 Employee and Directors Stock Plan (Incorporated by reference to Exhibit 10.19 to our Quarterly Report on Form 10-Q filed November 3, 2006).
10.30†		Form of Amendment to Restricted Stock Agreement under the KCS Energy, Inc. 2001 Employee and Directors Stock Plan (Incorporated by reference to Exhibit 10.5 to KCS Energy, Inc.’s Current Report on Form 8-K filed April 25, 2006).
10.31†		Form of Amendment to Supplemental Stock Option Agreement under KCS Energy, Inc.’s 2001 Employee and Directors Stock Plan (Incorporated by reference to Exhibit 10.5 to KCS Energy, Inc.’s Current Report on Form 8-K filed April 25, 2006).

 

90

---

Table of Contents

Index to Financial Statements

Exhibit No.		Description
10.32†		Executive Employment Agreement Form A for certain executives and Petrohawk Energy Corporation (Incorporated by reference to Exhibit 10.41 of our Annual Report on Form 10-K filed February 28, 2007).
10.33†		Executive Employment Agreement Form B for certain executives and Petrohawk Energy Corporation (Incorporated by reference to Exhibit 10.42 of our Annual Report on Form 10-K filed February 28, 2007).
10.34†		Amendment No. 2 to the KCS Energy, Inc. 2005 Employees and Directors Stock Plan (Incorporated by reference to Exhibit 10.43 of our Annual Report on Form 10-K filed February 28, 2007).
10.35†		Amendment No. 2 to the KCS Energy, Inc. 2001 Employees and Directors Stock Plan (Incorporated by reference to Exhibit 10.44 of our Annual Report on Form 10-K filed February 28, 2007).
10.36†		Amendment No. 1 to the Mission Resources Corporation 1996 Stock Incentive Plan (Incorporated by reference to Exhibit 10.45 of our Annual Report on Form 10-K filed February 28, 2007).
10.37		Second Amendment to Second Amended and Restated Senior Revolving Credit Agreement dated as of July 12, 2006 among the Company, each of the lenders from time to time party thereto, BNP Paribas, as administrative agent for the lenders, Bank of America, N.A. and BMO Capital Markets Financing, Inc., as co-syndication agents for the lenders, and JPMorgan Chase Bank, N.A., Wells Fargo Bank, N.A. and Fortis Capital Corp., as co-documentation agents for the lenders (Incorporated by reference to Exhibit 10.1 of our Quarterly Report on Form 10-Q filed August 8, 2007).
10.38		Third Amendment to Second Amended and Restated Senior Revolving Credit Agreement dated as of July 12, 2006 among the Company, each of the lenders from time to time party thereto, BNP Paribas, as administrative agent for the lenders, Bank of America, N.A. and BMO Capital Markets Financing, Inc., as co-syndication agents for the lenders, and JPMorgan Chase Bank, N.A., Wells Fargo Bank, N.A. and Fortis Capital Corp., as co-documentation agents for the lenders (Incorporated by reference to Exhibit 10.2 to our Quarterly Report on Form 10-Q Filed August 8, 2007).
10.39		Fourth Amendment to Second Amended and Restated Senior Revolving Credit Agreement dated as of July 12, 2006 among the Company, each of the lenders from time to time party thereto, BNP Paribas, as administrative agent for the lenders, Bank of America, N.A. and BMO Capital Markets Financing, Inc., as co-syndication agents for the lenders, and JPMorgan Chase Bank, N.A., Wells Fargo Bank, N.A. and Fortis Capital Corp., as co-documentation agents for the lenders (Incorporated by reference to Exhibit 10.2 to our Quarterly Report on Form 10-Q filed November 8, 2007).
10.40†		Form Amendment to Employment Agreement entered into on September 1, 2007 with Floyd C. Wilson, Larry L. Helm, Mark J. Mize, Stephen W. Herod and Richard K. Stoneburner (Incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed September 7, 2007).
10.41†		Employment Agreement entered into August 14, 2007 effective August 1, 2007 by and between Petrohawk Energy Corporation and David S. Elkouri (Incorporated by reference to Exhibit 10.4 to our Quarterly Report on Form 10-Q filed November 8, 2007).
10.42		Agreement of Sale and Purchase by and among Petrohawk Properties, LP, Petrohawk Energy Corporation, KCS Resources, Inc. and One TEC, LLC collectively, as Seller and Milagro Development I, LP as Purchaser – dated October 15, 2007 (Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed December 7, 2007).

 

91

---

Table of Contents

Index to Financial Statements

Exhibit No.		Description
10.43		Senior subordinated unsecured note of Milagro Development I, LP, as Maker (Incorporated by reference to Exhibit 10.2 of our Current Report on Form 8-K filed December 7, 2007).
10.44		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 of our Current Report on Form 8-K filed February 7, 2008).
10.45†		The Petrohawk Energy Corporation Third Amended and Restated 2004 Employee Incentive Plan (Incorporated by reference to Exhibit 10.1 of our Quarterly Report on Form 10-Q filed May 10, 2007).
10.46†		Amendment No. 3 to the KCS Energy, Inc. 2005 Employee and Directors Stock Plan (Incorporated by reference to Exhibit 10.2 of our Quarterly Report on Form 10-Q filed May 10, 2007).
10.47†		Form of Stock Appreciation Rights Agreement Annual Vesting Awards under the Petrohawk Energy Corporation Third Amended and Restated 2004 Employee Incentive Plan (Incorporated by reference to Exhibit 10.3 of our Quarterly Report on Form 10-Q filed May 10, 2007).
10.48†		Form of Restricted Stock Award Certificate under the KCS Energy, Inc. 2005 Employee and Directors Stock Plan (Incorporated by reference to Exhibit 10.4 of our Quarterly Report on Form 10-Q filed May 10, 2007).
10.49†		Form of Restricted Stock Award Agreement pursuant to the KCS Energy, Inc. 2005 Employee and Directors Stock Plan (Incorporated by reference to Exhibit 10.5 of our Quarterly Report on Form 10-Q filed May 10, 2007).
10.50†		Form of Stock Appreciation Rights Agreement Annual Vesting Awards under the KCS Energy, Inc. 2005 Employee and Directors Stock Plan (Incorporated by reference to Exhibit 10.6 of our Quarterly Report on Form 10-Q filed May 10, 2007).
10.52†		Amendment No. 1 to the Petrohawk Energy Corporation Third Amended and Restated 2004 Employee Incentive Plan (Incorporated by reference to our Registration Statement on Form S-8 (File No. 333-148434) filed January 2, 2008).
12.1*		Computation of Ratio of Earnings to Combined Fixed Charges and Preference Dividends
14.1		Code of Ethics for CEO and Senior Financial Officers (Incorporated by reference to Form 10-K/A filed on April 30, 2007).
21.1*		Subsidiaries of the Registrant
23.1*		Consent of Deloitte & Touche LLP
23.2*		Consent of Netherland, Sewell & Associates, Inc.
31.1*		Certificate of Chief Executive Officer under Section 302 of the Sarbanes-Oxley Act of 2002
31.2*		Certificate of Chief Financial Officer under Section 302 of the Sarbanes-Oxley Act of 2002

 

92

---

Table of Contents

Index to Financial Statements

Exhibit No.		Description
32*		Certifications required by Rule 13a-14(b) or Rule 15d-14(b) under the Securities and Exchange Act of 1934 and 18 U.S.C. Section 1350.
99.1*		Netherland, Sewell & Associates, Inc. Reserve Report

 

*	Filed herewith

†	Indicates management contract or compensatory plan or arrangement

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.

 

93

---

Table of Contents

Index to Financial Statements

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: February 27, 2008				By:		/s/    FLOYD C. WILSON
						Floyd C. Wilson
						Chairman of the Board, President and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

 

Signature		Title		Date
/S/    FLOYD C. WILSON         Floyd C. Wilson		Chairman of the Board, President and Chief Executive Officer		February 27, 2008
/S/    MARK J. MIZE         Mark J. Mize		Executive Vice President, Chief Financial Officer and Treasurer		February 27, 2008
/s/    JAMES W. CHRISTMAS         James W. Christmas		Vice Chairman and Director		February 27, 2008
/S/    TUCKER S. BRIDWELL         Tucker S. Bridwell		Director		February 27, 2008
/S/    THOMAS R. FULLER         Thomas R. Fuller		Director		February 27, 2008
/S/    JAMES L. IRISH, III         James L. Irish, III		Director		February 27, 2008
/S/    GARY A. MERRIMAN         Gary A. Merriman		Director		February 27, 2008
/S/    ROBERT G. RAYNOLDS         Robert G. Raynolds		Director		February 27, 2008
/S/    ROBERT C. STONE, JR.         Robert C. Stone, Jr.		Director		February 27, 2008
/S/    CHRISTOPHER A. VIGGIANO         Christopher A. Viggiano		Director		February 27, 2008

 

94