HK Energy Partners S-1 IPO registration

As filed with the Securities and Exchange Commission on October 30, 2007

Registration Statement No. 333-            

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

HK ENERGY PARTNERS LP

(Exact name of registrant as specified in its charter)

Delaware	1311	26-1285390
(State or other jurisdiction of incorporation or organization)	(Primary Standard Industrial Classification Code Number)	(I.R.S. Employer Identification No.)

1000 Louisiana, Suite 5810

Houston, Texas 77002

(832) 204-2700

(Address, including zip code, and telephone number,

including area code, of registrant’s principal executive offices)

Floyd C. Wilson

President and Chief Executive Officer

1000 Louisiana, Suite 5810

Houston, Texas 77002

(832) 204-2700

(Name, address, including zip code, and telephone number,

including area code, of agent for service)

Copies to:

William T. Heller IV Harry R. Beaudry Thompson & Knight LLP 333 Clay Street, Suite 3300 Houston, Texas 77002 (713) 654-8111 James M. Prince Vinson & Elkins L.L.P. 1001 Fannin Street, Suite 2500 Houston, Texas 77002 (713) 758-2222

Approximate date of commencement of proposed sale to the public:

As soon as practicable after the effective date of this Registration Statement.

If any of the securities being registered on this Form are being offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box.  ¨

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, please check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ¨

If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ¨

If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ¨

CALCULATION OF REGISTRATION FEE

Title of each Class of Securities to be Registered	Proposed Maximum Aggregate Offering Price(1)(2)	Amount of Registration Fee
Common Units representing limited partner interests	$212,750,000	$6,532

(1) Includes common units issuable upon exercise of the underwriters’ option to purchase additional common units.

(2) Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(o).

The registrant hereby amends this registration statement on such date or dates as may be necessary to delay its effective date until the registrant shall file a further amendment which specifically states that this registration statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933, or until the registration statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

The information in this preliminary prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This document is not an offer to sell these securities and we are not soliciting an offer to buy these securities in any state where the offer or sale is not permitted.

Subject to Completion, dated October 30, 2007

PROSPECTUS

9,250,000 Common Units

Representing Limited Partner Interests

HK Energy Partners LP is a growth oriented Delaware limited partnership recently formed by Petrohawk Energy Corporation (NYSE: HK) to acquire, develop and exploit oil and natural gas properties. We are offering 9,250,000 common units representing limited partner interests. This is the initial public offering of our common units. No public market currently exists for our common units. We expect the initial offering price to be between $         and $        per common unit. We intend to apply to list our common units on The New York Stock Exchange under the symbol “HKE.”

Investing in our common units involves risks. Please read “Risk Factors” beginning on page 19.

These risks include the following:

• Unless we replace the oil and natural gas reserves we produce, our production and revenues will decline, which would adversely affect our cash flow from operations and our ability to make distributions to our unitholders.

• If oil or gas prices decline significantly for a prolonged period, we may lower our distributions or not pay distributions at all.

• Our development operations will require substantial capital expenditures, which will reduce our cash available for distribution. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a decline in our production and reserves.

• We intend to pay holders of our common units distributions of $0.35 per unit for each quarter (or $1.40 per unit annually) before we pay distributions to holders of our subordinated units. For the year ended December 31, 2006 and the twelve months ended June 30, 2007, we would not have had enough cash available to pay the full $0.35 per common unit quarterly distribution to the holders of the common units or the distribution to the holders of the subordinated units.

• We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to our general partner, to enable us to make cash distributions to holders of our common units and subordinated units at the minimum quarterly distribution rate under our cash distribution policy.

• We may incur substantial debt in the future. This debt may restrict our ability to make distributions.

• Our general partner and its affiliates control us and will have conflicts of interest with us. Our partnership agreement limits the fiduciary duties that our general partner owes to us, which may permit it to favor its own interests to your detriment, and limits the circumstances under which you may make a claim relating to conflicts of interest and the remedies available to you in that event.

• If you are not an “Eligible Holder” (generally a United States citizen or entity), you will not be entitled to receive distributions or allocations of income or loss on your common units, and your common units will be subject to redemption at a price that may be below the current market price.

• You may be required to pay taxes on income earned by us even though your cash distributions from us are less than your share of our income.

	Per Common Unit	Total
Initial public offering price	$	$
Underwriting discount	$	$
Proceeds, before expenses, to HK Energy Partners LP	$	$

We have granted the underwriters a 30-day option to purchase up to an additional 1,387,500 common units from us on the same terms and conditions as set forth above if the underwriters sell more than 9,250,000 common units in this offering.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

Lehman Brothers, on behalf of the underwriters, expects to deliver the common units on or about                     , 2007.

LEHMAN BROTHERS WACHOVIA SECURITIES

                    , 2007

TABLE OF CONTENTS

	Page
PROSPECTUS SUMMARY	1
HK Energy Partners LP	1
Our Relationship with Petrohawk	4
Risk Factors	7
Summary of Conflicts of Interest and Fiduciary Duties	7
Formation Transactions and Partnership Structure	7
Management of HK Energy Partners LP	8
Other Information	9
The Offering	10
Summary Historical and Pro Forma Financial Data	15
Summary Reserve and Operating Data	18
RISK FACTORS	19
Risks Related to Our Business	19
Risks Inherent in an Investment in Us	30
Tax Risks to Common Unitholders	38
FORWARD-LOOKING STATEMENTS	42
USE OF PROCEEDS	43
CAPITALIZATION	44
DILUTION	45
OUR CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS	46
General	46
Our Minimum Quarterly Distribution Rate	48
Pro Forma Financial Information and Financial Forecast	49
Unaudited Pro Forma Available Cash for the Year Ended December 31, 2006 and for the Twelve Months Ended June 30, 2007	50
Estimated Cash Available for Distribution for the Twelve Months Ending December 31, 2008	53
Assumptions and Considerations	56
Operations and Revenue	57
Capital Expenditures and Operating Expenses	60
Distributions	62
Sensitivity Analysis	62
HOW WE WILL MAKE CASH DISTRIBUTIONS	64
Distributions of Available Cash	64
Operating Surplus and Capital Surplus	65
Subordination Period	68
Distributions of Available Cash from Operating Surplus during the Subordination Period	69

	Page
Distributions of Available Cash from Operating Surplus after the Subordination Period	69
Incentive Distribution Rights	69
General Partner’s Right to Reset Target Distribution Levels	70
Percentage Allocations of Available Cash from Operating Surplus	73
Distributions from Capital Surplus	73
Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels	74
Distributions of Cash Upon Liquidation	74
SELECTED HISTORICAL AND PRO FORMA FINANCIAL AND OPERATING DATA	77
Adjusted EBITDA	81
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	82
Overview	82
How We Evaluate Our Operations	82
Outlook	84
Factors Affecting Comparability of Future Results	85
Comparison of Results of Operations	86
Capital Resources and Liquidity	91
Off-Balance Sheet Arrangements	95
Plan of Operation for 2008	95
Quantitative and Qualitative Disclosures About Market Risks	96
Critical Accounting Policies and Estimates	96
Recently Issued Accounting Standards	99
Interest Sensitivity	99
BUSINESS	100
Overview	100
Business Strategy	101
Competitive Strengths	102
Our Properties	103
Our Relationship with Petrohawk	104
Oil and Natural Gas Data	106
Well Operations	108
Oil and Natural Gas Leases	109
Hedging Activity	109
Competition	109
Title to Properties	109
Seasonal Nature of Business	110
Environmental Matters and Regulation	110
Employees	115

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	Page
Offices	115
Legal Proceedings	115
MANAGEMENT	116
Management of HK Energy Partners LP	116
Directors and Executive Officers	117
Reimbursement of Expenses of Our General Partner	118
Executive Compensation	119
Compensation Discussion and Analysis	119
Compensation of Directors	119
Long-Term Incentive Plan	119
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT	122
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS	123
Distributions and Payments to Our General Partner and its Affiliates	123
Agreements Governing the Transactions	124
Administrative Services Agreement	124
Contribution Agreement	124
CONFLICTS OF INTEREST AND FIDUCIARY DUTIES	126
Conflicts of Interest	126
Fiduciary Duties	131
DESCRIPTION OF THE COMMON UNITS	134
The Units	134
Transfer Agent and Registrar	134
Transfer of Common Units	134
THE PARTNERSHIP AGREEMENT	136
Organization and Duration	136
Purpose	136
Power of Attorney	136
Cash Distributions	136
Capital Contributions	137
Voting Rights	137
Limited Liability	138
Issuance of Additional Securities	139
Amendment of the Partnership Agreement	140
Merger, Consolidation, Conversion, Sale or Other Disposition of Assets	142
Termination and Dissolution	142
Liquidation and Distribution of Proceeds	143
Withdrawal or Removal of the General Partner	143
Transfer of General Partner Interest	144
Transfer of Ownership Interests in the General Partner	145
Transfer of Incentive Distribution Rights	145
Change of Management Provisions	145

	Page
Limited Call Right	146
Meetings; Voting	146
Status as Limited Partner	147
Non-Eligible Holders; Redemption	147
Indemnification	148
Reimbursement of Expenses	148
Books and Reports	148
Right to Inspect Our Books and Records	149
Registration Rights	149
UNITS ELIGIBLE FOR FUTURE SALE	150
MATERIAL TAX CONSEQUENCES	151
Partnership Status	152
Limited Partner Status	153
Tax Consequences of Unit Ownership	153
Tax Treatment of Operations	159
Disposition of Units	163
Uniformity of Units	165
Tax-Exempt Organizations and Other Investors	165
Administrative Matters	166
State, Local and Other Tax Considerations	168
INVESTMENT IN US BY EMPLOYEE BENEFIT PLANS	170
UNDERWRITING	171
Commissions and Expenses	171
Option to Purchase Additional Common Units	171
Lock-Up Agreements	172
Offering Price Determination	172
Indemnification	173
Directed Unit Program	173
Stabilization, Short Positions and Penalty Bids	173
Electronic Distribution	174
The New York Stock Exchange	174
Discretionary Sales	174
Relationships/NASD Conduct Rules	174
VALIDITY OF THE COMMON UNITS	175
EXPERTS	175
WHERE YOU CAN FIND MORE INFORMATION	175
INDEX TO FINANCIAL STATEMENTS	F-1
APPENDIX A — FIRST AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP OF HK ENERGY PARTNERS LP	A-1
APPENDIX B — GLOSSARY OF TERMS	B-1
APPENDIX C — JUNE 30, 2007 REPORT OF NETHERLAND, SEWELL & ASSOCIATES, INC.	C-1

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You should rely only on the information contained in this prospectus. We have not, and the underwriters have not, authorized anyone to provide you with different information. If anyone provides you with different or inconsistent information, you should not rely on it. We are not, and the underwriters are not, making an offer to sell these securities in any jurisdiction where an offer or sale is not permitted. You should assume that the information appearing in this prospectus is accurate as of the date on the front cover of this prospectus. Our business, financial condition, results of operations and prospects may have changed since that date.

Until                     , 200   (25 days after the date of this prospectus), all dealers that effect transactions in these securities, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealers’ obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.

Our natural gas and crude oil proved reserve information as of June 30, 2007 included in this prospectus is based on a reserve report prepared by Netherland, Sewell & Associates, Inc., or NSAI, an independent engineering firm. A summary of this report is provided in Appendix C and is referred to in this prospectus as the “reserve report”.

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PROSPECTUS SUMMARY

This summary highlights selected information contained elsewhere in this prospectus. You should read the entire prospectus carefully, including the historical and pro forma financial statements and notes to those financial statements. The information presented in this prospectus assumes an initial public offering price of $20.00 per common unit and, unless otherwise noted, that the underwriters’ option to purchase additional common units is not exercised. You should read “Risk Factors” beginning on page 19 for more information about important factors that you should consider carefully before buying our common units. We include a glossary of some of the oil and natural gas terms used in this prospectus as Appendix B.

References in this prospectus to “HK Energy Partners,” “the partnership,” “we,” “our,” “us” or similar terms refer to HK Energy Partners LP and its subsidiaries. References in this prospectus to “HK GP” or “our general partner” refer to HK Energy Partners GP LP, our general partner. References in this prospectus to “HK Management” or “our management” refer to Petrohawk Management Company, LLC, the general partner of our general partner. References in this prospectus to “Petrohawk” refer to Petrohawk Energy Corporation, the ultimate parent company of our general partner, and its wholly owned subsidiaries, including HK Management. References in this prospectus to the “partnership properties” or “our properties” refer to the combination of oil and natural gas properties contributed and sold to us by subsidiaries of Petrohawk in connection with this offering. Unless otherwise noted, references in this prospectus to our properties on a “pro forma combined basis” refer to our properties as if they had been contributed and sold to us by Petrohawk on January 1, 2006.

HK Energy Partners LP

We are a growth oriented Delaware limited partnership formed in October 2007 by Petrohawk Energy Corporation (NYSE: HK) to acquire, develop and exploit oil and natural gas properties. Our properties are primarily located in the Permian Basin region in West Texas and southeastern New Mexico.

At June 30, 2007, our oil and natural gas properties had estimated net proved reserves of 145.3 Bcfe, of which approximately 72% were natural gas and 79% were proved developed. For the six months ended June 30, 2007, on a pro forma combined basis, our properties produced approximately 26.3 MMcfe/d. Our producing properties are located in mature fields that exhibit relatively long-lived production, with a reserve to production ratio of 15 years, based on our estimated proved reserves as of June 30, 2007 and our annualized production for the six months ended June 30, 2007.

Our primary business objective is to generate stable cash flows through maintaining our current production levels and asset base over the long term in a manner that will allow us to make quarterly cash distributions to our unitholders at the minimum quarterly distribution rate of $0.35 per unit and, over time, to grow our production and asset base to increase our quarterly cash distribution rate. We intend to rely on the significant operating and acquisition experience of Petrohawk’s management team, acting for our general partner, to execute our growth strategy. Subsequent to the arrival of Petrohawk’s current management in May 2004, Petrohawk increased its proved reserves from approximately 219 Bcfe as of December 31, 2004 to approximately 1,076 Bcfe as of December 31, 2006 and increased its average daily production from approximately 29 MMcfe/d for the three month period ended December 31, 2004 to approximately 321 MMcfe/d for the six months ended June 30, 2007, primarily through strategic acquisitions of oil and natural gas properties and the drilling and exploitation of those properties.

We intend to pay a minimum quarterly cash distribution of $0.35 per unit, or $1.40 per unit annually, to holders of our common units. We will pay this distribution, which we refer to as our minimum quarterly

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distribution, on all of our common units before paying quarterly distributions on our subordinated units, which constitute 25% of our limited and general partner interests. To achieve more predictable cash flows and to reduce our exposure to adverse fluctuations in the prices of oil and natural gas, we intend to implement an active hedging program covering a significant portion of our expected oil and natural gas production.

Our Properties

Our principal properties are located in the Permian Basin, which is one of the largest and most prolific oil and natural gas producing basins in the United States. The Permian Basin extends over 100,000 square miles in West Texas and southeastern New Mexico and has produced over 26 billion Bbls of oil and 85 Tcf of natural gas since its discovery in 1921. This basin is characterized by oil and natural gas fields with large accumulations of original hydrocarbons in place, long production histories, and multiple producing formations. Because of these inherent qualities, we believe properties in this region are well suited for our partnership and its business objectives.

Our producing properties in the Permian Basin are mature fields with relatively predictable production and with relatively low production declines. We intend to pursue relatively low risk development drilling and workover projects designed to partially offset our natural production decline rates in our existing fields. We expect to drill a total of 22 gross (7.1 net) wells and complete 37 (14 net) workovers on our properties during 2007 with annual budgeted spending of $14 million, of which 13 wells (1.7 net) have been drilled and 25 (7.6 net) workovers have been completed at a cost of approximately $7 million (net) as of June 30, 2007. For the year ending December 31, 2008, we anticipate drilling a total of 47 (12.1 net) wells and completing 44 (16.4 net) workovers with budgeted spending of approximately $16 million (net).

The following table is a summary of the proved reserves and production of our oil and natural gas properties as of June 30, 2007.

Field	As of June 30, 2007(1)						1st Half 2007 Average Daily Production	Reserve-to- Production Ratio(3)	Estimated Production Decline Rate(4)
	Estimated Proved Reserves	Percent of Total Proved Reserves		Percent Natural Gas(2)		Estimated Proved Developed Reserves
	(Bcfe)					(Bcfe)	(MMcfe/d)	(Years)
Texas
Waddell Ranch	42.3	29.1	%	46.1	%	33.9	5.9	19.6	10	%
Sawyer	38.3	26.3	%	99.1	%	28.9	10.6	9.9	12	%
TXL North	24.2	16.7	%	36.8	%	20.0	3.1	21.4	7	%
New Mexico
Jalmat	38.3	26.4	%	94.4	%	30.4	6.1	17.2	13	%
Oklahoma
Carpenter / Carpenter NE	2.2	1.5	%	99.7	%	2.2	0.6	10.1	12	%
Total	145.3	100.0	%	72.1	%	115.4	26.3	15.1	11	%

(1) Our natural gas and oil proved reserve information as of June 30, 2007 is based on a reserve report prepared by Netherland, Sewell & Associates, Inc., an independent engineering firm (“NSAI”). See Appendix C.

(2) Calculated using natural gas equivalents of six Mcf of natural gas per Bbl of oil. NGLs are included in natural gas.

(3) The reserve-to-production ratio is calculated by dividing our estimated net proved reserves as of June 30, 2007 by our annualized average daily production for the six months ended June 30, 2007.

(4) Represents percentage decrease in annual production from our proved developed producing reserves in 2009 when compared to 2008 as estimated by NSAI.

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Texas Properties

Our Texas properties include our Waddell Ranch, Sawyer and TXL North fields. Our interests in these fields encompass approximately 111,000 gross (43,000 net) acres and are located in Crane, Sutton and Ector counties. The producing formations in our Texas properties range in depth from 3,000 to 11,000 feet and activity in these fields focuses primarily on infill development drilling. We have identified approximately 1,000 development drilling locations as well as approximately 110 workover and exploitation projects. In 2008, we plan to spend a total of $11 million on our Texas properties, including $9.4 million for drilling and completing 47 gross wells (12.1 net) and $1.6 million for 31 (4 net) workover and exploitation projects.

New Mexico Property

Our property in southeastern New Mexico consists of the Jalmat field. Our interests in this field encompass approximately 9,400 gross (8,900 net) acres located in Lea County. The producing formations in this field range in depth from 2,700 to 4,000 feet and activity in this field focuses primarily on workover projects. We have identified 45 exploitation projects that consist primarily of workover and redrill activities. In 2008, we plan to spend a total of $5 million on 13 (12.4 net) workover projects on our New Mexico property.

Business Strategy

Our primary business objective is to generate stable cash flows through maintaining our current production levels and asset base over the long term in a manner that will allow us to make quarterly cash distributions to our unitholders and, over time, to grow our production and asset base to increase our quarterly cash distribution rate. We intend to accomplish this objective by executing the following business strategies:

• Make accretive acquisitions of properties with long-lived, stable and predictable production profiles:

• directly from Petrohawk through negotiated transactions;

• by cooperating with Petrohawk in pursuit of attractive acquisition candidates; and

• from third-parties independent of Petrohawk;

• Maintain a multi-year inventory of relatively low risk drilling locations and exploitation projects;

• Reduce the volatility in our cash flows through our commodity hedging activities; and

• Leverage the technical and managerial expertise of Petrohawk to develop and exploit our existing assets and to grow through acquisitions.

Competitive Strengths

We believe the following competitive strengths will enable us to achieve our primary business objective and successfully execute our strategies:

• Our substantial inventory of identified development drilling locations and exploitation projects;

• Our oil and natural gas properties are characterized by long-lived reserves with relatively predictable production profiles; and

• Our relationship with Petrohawk, which provides us with:

• the opportunity to acquire assets directly from and jointly with Petrohawk;

• the ability to leverage Petrohawk’s technical expertise to implement our acquisition, development and exploitation strategy;

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• access to the substantial acquisition, integration and operational experience of Petrohawk’s management team; and

• the experience of Petrohawk’s management team in the oil and natural gas industry, including significant experience in the Permian Basin and other regions with properties characterized by stable and predictable production profiles and long-lived reserves.

Hedging

An important part of our business strategy includes hedging a portion of our oil and natural gas production to reduce our exposure to fluctuations in the prices of oil and natural gas and achieve more predictable cash flows. As of October 25, 2007, Petrohawk has entered into swap agreements covering 3,660,000 MMBtu of natural gas and 275 MBbls of oil for each of calendar years 2008, 2009 and 2010. The hedged volumes represent approximately 56% of our forecasted total production of 9,405 MMcfe for the twelve months ending December 31, 2008 at weighted average prices of $8.25 per MMBtu for natural gas and $81.17 per Bbl for oil. Petrohawk will assign those derivative contracts to us at the closing of this offering. Petrohawk intends to enter into additional derivative financial instruments so that approximately 80% to 85% of our estimated net production of oil and natural gas from proved developed producing reserves will be covered by derivatives through December 31, 2010. The form of these derivatives is expected to be fixed-price swaps and puts. By removing a portion of price volatility associated with our future oil and natural gas production we have mitigated, but not eliminated, the potential effects of changing oil and natural gas prices on our cash flows from operations for those periods. For more information on our hedging arrangements, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — How We Evaluate Our Operations — Derivative Instruments and Hedging Activities.”

Our Relationship with Petrohawk

One of our principal strengths is our relationship with Petrohawk (NYSE: HK), a publicly traded independent oil and natural gas company. Petrohawk is engaged in the acquisition and development of oil and natural gas reserves from onshore fields in the United States and seeks to acquire a balanced, geographically diverse portfolio of long-lived, lower risk reserves along with shorter lived, higher margin reserves. As of December 31, 2006, and including the interests to be conveyed to us, Petrohawk’s total estimated proved reserves were 1,076 Bcfe, consisting of 24 MMBbls of oil and condensate and 930 Bcf of natural gas and NGLs located primarily in the Mid-Continent region (including 204 Bcfe in the Gulf Coast region that Petrohawk has signed a definitive agreement to divest). Upon completion of this offering, Petrohawk will have a significant interest in us through its ownership of 5,904,048 common units and 5,189,742 subordinated units, representing a 53.4% limited partner interest in us, a 2% general partner interest in us and all of our incentive distribution rights.

A principal component of our business strategy is to grow our proved reserves and production through the acquisition of oil and natural gas properties characterized by long-lived, stable and predictable production profiles and that have substantial opportunities for further development and exploitation. We intend to leverage the significant experience of Petrohawk’s management team to execute our growth strategy. Petrohawk has an established track record of successfully acquiring, developing, exploiting and operating oil and natural gas properties. Subsequent to the arrival of Petrohawk’s current management in May 2004, Petrohawk has increased its proved reserves from approximately 219 Bcfe as of December 31, 2004 to approximately 1,076 Bcfe as of December 31, 2006, and has increased its average daily production from approximately 29 MMcfe/d for the three months ended December 31, 2004 to approximately 321 MMcfe/d for the six months ended June 30, 2007, primarily through strategic acquisitions of oil and natural gas properties and the drilling and exploitation of those properties. After the contribution of the partnership properties to us, Petrohawk will continue to own and operate properties with estimated net proved reserves as of December 31, 2006 of 927 Bcfe (including 204 Bcfe in the Gulf Coast region that Petrohawk has signed a definitive agreement to divest), which include some properties with characteristics that are or, after additional capital is invested, may be well suited for our partnership.

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Petrohawk views us as an integral part of its growth strategy. It may be in Petrohawk’s best interest to sell additional assets to us in the future. Nonetheless, no assurance can be provided as to which, if any, assets may be made available to us by Petrohawk as Petrohawk is not obligated to offer us assets for acquisition, or if we will choose to pursue the opportunity to acquire such assets if they are made available to us. Furthermore, Petrohawk evaluates acquisitions and divestitures and may elect to acquire or divest oil and natural gas properties in the future without offering us the opportunity to participate. After this offering, Petrohawk will continue to be free to act in a manner that is beneficial to its interests and may be detrimental to ours, which may include competing with us for future acquisition opportunities. Accordingly, while our relationship with Petrohawk and its subsidiaries is a significant strength, it also is a source of potential conflicts. See “Conflicts of Interest and Fiduciary Duties.”

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Organizational Chart

The following diagram depicts our organizational structure and ownership after giving effect to this offering and the related formation transactions, assuming that the underwriters’ option to purchase additional common units is not exercised.

Public Common Units	45	%
Petrohawk
Common Units	28	%
Subordinated Units	25	%
General Partner Interests	2	%

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Risk Factors

An investment in our common units involves risks associated with our business, regulatory and legal matters, our limited partnership structure and the tax characteristics of our common units. Please read carefully the risks under “Risk Factors” beginning on page 19.

Summary of Conflicts of Interest and Fiduciary Duties

Conflicts of Interest. Our general partner has a legal duty to manage us in a manner beneficial to our unitholders. This legal duty originates in statutes and judicial decisions and is commonly referred to as a “fiduciary duty.” However, because our general partner and its general partner, HK Management, are owned by Petrohawk, the officers and directors of HK Management also have fiduciary duties to manage our general partner in a manner beneficial to Petrohawk. As a result of this relationship, conflicts of interest may arise in the future between us and holders of our common units, on the one hand, and our general partner and its affiliates, including Petrohawk and its subsidiaries, on the other hand.

Partnership Agreement Modifications of Fiduciary Duties. Our partnership agreement limits the liability and reduces the fiduciary duties of our general partner to us and our unitholders. Our partnership agreement also restricts the remedies available to our unitholders for actions that might otherwise constitute a breach of our general partner’s fiduciary duties owed to our unitholders. Our partnership agreement also provides that Petrohawk and its affiliates may own assets or engage in businesses that compete with us. For example, Petrohawk or its affiliates may acquire, invest in or dispose of oil and natural gas exploration and production or other assets in the future without any obligation to offer us the opportunity to purchase or own interests in those assets, and Petrohawk may, at any time alter its strategy, including determining that we no longer constitute an integral component of Petrohawk’s growth. Petrohawk is also not under any obligation to make any acquisitions on our behalf. By purchasing a common unit, the purchaser agrees to be bound by the terms of our partnership agreement and, pursuant to the terms of our partnership agreement, each holder of common units consents to various actions contemplated in the partnership agreement and conflicts of interest that might otherwise be considered a breach of fiduciary or other duties under applicable state law.

For a more detailed description of the conflicts of interest and fiduciary duties of our general partner, see “Risk Factors — Risks Inherent in an Investment in Us” and “Conflicts of Interest and Fiduciary Duties.”

Formation Transactions and Partnership Structure

We are a Delaware limited partnership formed in October 2007. Our general partner, HK Energy Partners GP LP, has sole responsibility for conducting our business and managing our operations. The board of directors of Petrohawk Management Company, LLC, which is the general partner of HK Energy Partners GP LP, a wholly owned subsidiary of Petrohawk, will be responsible for directing the business and operations of our general partner. Our operations will be conducted through, and our operating assets will be owned by, our operating subsidiaries. We own, directly or indirectly, all of the ownership interests in our operating subsidiaries. We, our subsidiaries and our general partner do not have employees.

In connection with the closing of this offering:

• we will enter into a contribution agreement with certain wholly-owned subsidiaries of Petrohawk and our general partner pursuant to which:

• our general partner and another subsidiary of Petrohawk will contribute all of the partnership properties to us;

• we will issue 5,904,048 common units and 5,189,742 subordinated units to wholly owned subsidiaries of Petrohawk, representing an aggregate 53.4% limited partner interest in us as partial consideration for such contribution;

• subsidiaries of Petrohawk will agree to indemnify us for certain environmental and tax liabilities and title defects, as well as relating to retained assets and liabilities, occurring or existing before the closing;

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• we will sell 9,250,000 common units to the public in this offering, representing a 44.6% limited partner interest in us, and will use the proceeds as described in “Use of Proceeds”;

• we will issue to HK Energy Partners GP LP a 2% general partner interest in us and all of our incentive distribution rights, which will entitle our general partner to increasing percentages of the cash we distribute in excess of $0.4025 per unit per quarter (115% of the minimum quarterly distribution);

• we expect to borrow $165.0 million in term debt under our credit facility which will be secured by $165.0 million of qualifying investment grade securities, and distribute the funds to our general partner and another subsidiary of Petrohawk as partial consideration for the partnership properties contributed to us;

• we expect to borrow $58.1 million in revolving debt under our credit facility and distribute the funds to our general partner and another subsidiary of Petrohawk;

• we will enter into an administrative services agreement with Petrohawk, HK Management and our general partner pursuant to which we will reimburse Petrohawk and its affiliates for the payment of certain operating expenses and for providing various general and administrative services to us.

Management of HK Energy Partners LP

HK Energy Partners GP LP, our general partner, is an indirect, wholly owned subsidiary of Petrohawk and has sole responsibility for conducting our business and for managing our operations. Because our general partner is a limited partnership, its general partner, HK Management, will conduct our business and operations, and the board of directors and officers of HK Management will make decisions on our behalf. Petrohawk will elect all seven directors of HK Management, with at least three directors meeting the independence standards established by The New York Stock Exchange, one of whom will be elected to the board as of the closing of this offering. Services will be provided to HK Energy Partners GP LP and us by officers and other employees of Petrohawk and its subsidiaries. For more information about these individuals, see “Management — Directors and Executive Officers.”

At the closing of this offering, we intend to enter into an administrative services agreement with Petrohawk, HK Management and our general partner pursuant to which Petrohawk and its subsidiaries will perform administrative services for us such as accounting, business development, finance, land, legal, engineering, investor relations, management, marketing, information technology, insurance, government regulations, communications, regulatory, environmental and human resources. Petrohawk and its subsidiaries will not be liable to us for their performance of, or failure to perform, services under the administrative services agreement unless their acts or omissions constitute gross negligence or willful misconduct. Petrohawk and its subsidiaries will be reimbursed for their costs incurred in providing such services to us, including for salary, bonus, incentive compensation and other amounts paid by Petrohawk and its subsidiaries to persons who perform services for us or on our behalf. Our general partner is entitled to determine in good faith the expenses that are allocable to us. Petrohawk has informed us that it intends initially to structure the reimbursement of these costs in the form of a monthly billing of a portion of Petrohawk’s corporate and other expenses, representing an estimated allocable share of time spent by the officers and employees of Petrohawk and its subsidiaries on our operations. We expect that the annual reimbursement charge will be approximately $2.9 million and will be pro-rated for the initial period from the closing of this offering through December 31, 2008. Petrohawk has indicated that it expects that it will review at least annually with the board of directors of HK Management this reimbursement arrangement and any changes to the amount or methodology by which it is determined. In addition, we will incur additional third party expenses, such as those incurred as a result of our being a public company, which we expect to approximate $2.8 million annually. See “Certain Relationships and Related Transactions.”

As is common with publicly traded limited partnerships and in order to maximize operational flexibility, we will conduct our operations through subsidiaries. We will have several direct operating subsidiaries initially, which will conduct business through themselves and their subsidiaries.

8

Other Information

Our principal executive offices are located at 1000 Louisiana, Suite 5810, Houston, Texas 77002 and our telephone number is                     . We expect our internet address to be www.                     .com. We expect to make our periodic reports and other information filed with or furnished to the Securities and Exchange Commission, which we refer to as the SEC, available, free of charge, through our website, as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference into this prospectus and does not constitute a part of this prospectus.

9

The Offering

Common units offered to the public 9,250,000 common units; 10,637,500 common units if the underwriters exercise their option to purchase additional common units in full.

Units outstanding after this offering 15,154,048 common units and 5,189,742 subordinated units, representing 73% and 25%, respectively, of our limited and general partner interests. The general partner will own a 2% general partner interest in us.

If the underwriters exercise their option to purchase additional common units in full, 16,541,548 common units and 5,189,742 subordinated units, representing 75% and 23%, respectively, of our limited and general partner interests will be outstanding after this offering.

Use of proceeds We estimate that we will receive net proceeds of approximately $170.0 million from the sale of 9,250,000 common units offered by this prospectus, assuming an offering price of $20.00 per unit and after deducting underwriting discounts, a structuring fee and estimated offering expenses. We anticipate using the aggregate net proceeds of this offering to:

• purchase $165.0 million of qualifying investment grade securities, which will be assigned as collateral to secure the term loan portion of our credit facility; and

• fund $5.0 million of working capital.

We also anticipate that we will borrow approximately $165.0 million in term debt and $58.1 million in revolving debt upon the closing of this offering, and we will distribute the aggregate amount of the net proceeds from such borrowings to subsidiaries of Petrohawk, which distribution will be made in partial consideration of the assets contributed to us upon the closing of this offering.

If the underwriters’ option to purchase additional common units is exercised in full, we will use the net proceeds of approximately $25.8 million (also assuming an offering price of $20.00 per unit) to repay a portion of our anticipated borrowings under our revolving credit facility.

Cash distributions We intend to make minimum quarterly distributions of $0.35 per unit per quarter ($1.40 per unit on an annualized basis) to the extent we have sufficient cash from our operations after establishment of cash reserves and payment of fees and expenses, including payments to our general partner and its affiliates. Assuming that we become a publicly traded partnership before March 31, 2008, we will pay unitholders a prorated distribution for the period from the first day our common units are publicly traded to and including March 31, 2008. We expect to pay this cash distribution on or before May 15, 2008. We intend to retain substantial cash reserves to finance the capital expenditures necessary to maintain our existing levels of production and asset base over the long term. Our ability to pay cash distributions at this

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minimum quarterly distribution rate is subject to various restrictions and other factors described in more detail under “Our Cash Distribution Policy and Restrictions on Distributions.”

Our partnership agreement requires us to distribute all of our cash on hand at the end of each quarter, beginning with the quarter ending March 31, 2008, less reserves established by our general partner. We refer to this cash as “available cash,” and we define its meaning in our partnership agreement attached as Appendix A.

All of our cash distributions will be characterized as coming from either operating surplus or capital surplus. Operating surplus is defined in our partnership agreement and generally means amounts we receive from operating sources, such as sales of our oil and natural gas production, less operating expenditures, such as production costs and taxes and less estimated average maintenance capital expenditures, which are generally amounts we estimate we will spend in the future to maintain our existing production levels and asset base over the long term. Capital surplus generally means amounts we receive from non-operating sources such as sales of properties and issuances of debt or equity securities or borrowings, other than short term working capital borrowings. We distribute operating surplus differently than capital surplus. We do not expect to make any distributions of available cash from capital surplus. Our partnership agreement requires that we distribute all of our available cash from operating surplus each quarter in the following manner:

• first, 98% to the holders of common units and 2% to our general partner, until each common unit has received a minimum quarterly distribution of $0.35 plus any arrearages from prior quarters;

• second, 98% to the holders of subordinated units and 2% to our general partner, until each subordinated unit has received a minimum quarterly distribution of $0.35;

• third, 98% to all unitholders, pro rata, and 2% to our general partner, until each unit has received an aggregate distribution of $0.4025;

• fourth, 85% to all unitholders, pro rata, and 15% to our general partner, until each unit has received an aggregate distribution of $0.4375; and

• thereafter, 75% to all unitholders, pro rata, and 25% to our general partner.

On a pro forma basis for the year ended December 31, 2006 and the twelve months ended June 30, 2007, we would have generated available cash of approximately $9.5 million and $18.3 million, respectively. This amount of pro forma cash available for distribution

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would have been sufficient to allow us to pay approximately 44% and 84%, respectively, of the minimum quarterly distributions on our common units during these periods (48% and 86%, respectively, assuming the underwriters exercise in full their option to purchase additional common units). See “Our Cash Distribution Policy and Restrictions on Distributions — Unaudited Pro Forma Available Cash for the Year Ended December 31, 2006 and for the Twelve Months Ended June 30, 2007.”

We believe that, based on the assumptions and factors included under “Our Cash Distribution Policy and Restrictions on Distributions — Assumptions and Considerations,” we will have sufficient cash available from operating surplus to make cash distributions for the four quarters ending December 31, 2008 at the minimum quarterly distribution rate of $0.35 per unit per quarter ($1.40 per common unit on an annualized basis) on all common units and subordinated units. See “Our Cash Distribution Policy and Restrictions on Distributions — Estimated Cash Available for Distribution for the Twelve Months Ending December 31, 2008.”

Subordinated units Following this offering, Petrohawk will beneficially own all of our subordinated units. The principal difference between our common units and subordinated units is that in any quarter during the subordination period, holders of the subordinated units are entitled to receive the minimum quarterly distribution from operating surplus of $0.35 per unit only after the common units have received the minimum quarterly distribution from operating surplus plus any arrearages in the payment of the minimum quarterly distribution from prior quarters and the general partner has received its 2% distribution. Accordingly, the holders of subordinated units may receive a smaller distribution than holders of common units or no distribution at all. Subordinated units will not accrue arrearages.

The subordination period will generally end on the first business day after we have earned and paid from operating surplus at least $0.35 per quarter on each outstanding common unit and subordinated unit and paid to the general partner the related amount representing its general partner interest for any three consecutive, non-overlapping four-quarter periods ending on or after December 31, 2010. The subordination period also will end upon the removal of our general partner other than for cause if the units held by our general partner and its affiliates are not voted in favor of such removal.

When the subordination period ends, all remaining subordinated units will convert into common units on a one-for-one basis, and the common units will no longer be entitled to arrearages. See “How We Will Make Distributions — Subordination Period.”

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General Partner’s right to reset the target distribution levels Our general partner has the right, at a time when there are no subordinated units outstanding and it has received incentive distributions at the highest level to which it is entitled (23%), for each of the prior four consecutive fiscal quarters, to reset the initial cash target distribution levels at higher levels based on the distribution at the time of the exercise of the reset election. Following a reset election by our general partner, the minimum quarterly distribution amount will be reset to an amount equal to the average cash distribution amount per common unit for the two fiscal quarters immediately preceding the reset election (‘‘reset minimum quarterly distribution’’) and the target distribution levels will be reset to correspondingly higher levels based on the same percentage increases above the reset minimum quarterly distribution amount as in our current target distribution levels.

In connection with resetting these target distribution levels, our general partner will be entitled to receive a number of Class B units equal to that number of common units whose aggregate quarterly cash distributions equaled the average of the distributions to our general partner on the incentive distribution rights in the prior two quarters. The Class B units will be entitled to the same cash distributions per unit as our common units and will be convertible into an equal number of common units at any time following the first anniversary of issuance. See “How We Will Make Cash Distributions — General Partner’s Right to Reset Target Distribution Levels.”

Issuance of additional units We can issue an unlimited number of units without the consent of our unitholders. See “Units Eligible for Future Sale” and “The Partnership Agreement — Issuance of Additional Securities.”

Limited voting rights Our general partner will manage and operate us. Unlike the holders of common stock in a corporation, you will have only limited voting rights on matters affecting our business. You will have no right to elect our general partner or its general partner, HK Management, or the directors of HK Management on an annual or other continuing basis. Our general partner may not be removed except by a vote of the holders of at least 66 ²/3% of the outstanding units, including any units owned by our general partner and its affiliates, voting together as a single class. Upon consummation of this offering our general partner and its owners and their affiliates will own an aggregate of 55.4% of our common and subordinated units and general partner interests. This will give our general partner the practical ability to prevent its involuntary removal. See “The Partnership Agreement — Voting Rights.”

Limited call right If at any time more than 80% of the outstanding common units are owned by our general partner and its affiliates, our general partner has the right, but not the obligation, to purchase all of the remaining common units at a price not less than the then-current market price of

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the common units. See “The Partnership Agreement — Limited Call Right.” At the end of the subordination period, assuming no additional issuances of common units, our general partner and its affiliates will own 55.4% of the common units and general partner interests.

Eligible Holders and redemption Only Eligible Holders will be entitled to receive distributions or be allocated income or loss from us. Eligible Holders are:

• individuals or entities subject to United States federal income taxation on the income generated by us; or

• entities not subject to United States federal taxation on the income generated by us, so long as all of the entity’s owners are subject to such taxation.

We have the right, which we may assign to any of our affiliates, but not the obligation, to redeem all of the common and subordinated units of any holder that is not an Eligible Holder or that has failed to certify or has falsely certified that such holder is an Eligible Holder. The purchase price for such redemption would be equal to the lower of the holder’s purchase price and the then-current market price of the units. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner.

See “Description of the Common Units — Transfer of Common Units” and “The Partnership Agreement — Non-Eligible Holders; Redemption.”

Estimated ratio of taxable income to distributions We estimate that if you own the common units you purchase in this offering through the record date for distributions for the period ending December 31, 2010, you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be     % or less of the cash distributed to you with respect to that period. For example, if you receive an annual distribution of $1.40 per unit, we estimate that your average allocable federal taxable income per year will be no more than $         per unit. See “Material Tax Consequences — Tax Consequences of Unit Ownership — Ratio of Taxable Income to Distributions” for the basis of this estimate.

Material tax consequences For a discussion of other material federal income tax consequences that may be relevant to prospective unitholders who are individual citizens or residents of the United States, see “Material Tax Consequences.”

Exchange listing We intend to apply to list our common units on The New York Stock Exchange under the symbol “HKE.”

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Summary Historical and Pro Forma Financial Data

The following section presents summary historical financial data for HK Energy Partners LP Predecessor, the predecessor to HK Energy Partners LP, and pro forma financial data of HK Energy Partners LP, as of the dates and for the periods indicated.

The statement of operations data for our predecessor for the years ended December 31, 2004, 2005 and 2006 and the balance sheet data as of December 31, 2005 and 2006 set forth below are derived from our audited carve out financial statements and the notes thereto included elsewhere in this document. The statement of operations data for our predecessor for the six months ended June 30, 2007 and 2006 and the balance sheet data as of June 30, 2007 are derived from our unaudited carve out financial statements included elsewhere in this document and, in the opinion of management, include all adjustments (consisting only of normal recurring accruals) necessary for a fair presentation of the financial position and results of operations as of the dates and for the periods indicated. The carve out financial statements of our predecessor are comprised of oil and natural gas assets, liabilities and operations located in the Permian Basin of West Texas and New Mexico currently owned by Petrohawk, which we refer to as the partnership properties, and which we will acquire upon completion of this offering. Due to the factors described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” our future results of operations may not be comparable to HK Energy Partners LP Predecessor’s historical results. The results for periods of less than a full year are not necessarily indicative of the results to be expected for any interim period or for a full year.

The summary pro forma statement of operations data presented for the year ended December 31, 2006 and as of and for the six months ended June 30, 2007 for HK Energy Partners LP give pro forma effect to the following as if all transactions had been completed on January 1, 2006:

• the acquisition by Petrohawk of KCS Energy, Inc. on July 12, 2006;

• our entrance into the contribution agreement, pursuant to which:

• our general partner and another subsidiary of Petrohawk will contribute all of the partnership properties to us;

• we will issue 5,904,048 common units and 5,189,742 subordinated units to wholly owned subsidiaries of Petrohawk, representing an aggregate 53.4% limited partner interest in us as partial consideration for such contribution;

• we will sell 9,250,000 common units to the public in this offering, representing a 44.6% limited partner interest in us, and will use the proceeds as described in “Use of Proceeds”; and

• we will issue to HK Energy Partners GP LP a 2% general partner interest in us and all of our incentive distribution rights, which will entitle our general partner to increasing percentages of the cash we distribute in excess of $0.4025 per unit per quarter (115% of the minimum quarterly distribution);

• expected borrowings of $165.0 million in term debt under our credit facility, which will be secured by $165.0 million of qualifying investment grade securities, and distribution of the funds to our general partner and another subsidiary of Petrohawk as partial consideration for the partnership properties contributed to us;

• expected borrowings of $58.1 million in revolving debt under our credit facility and distribution of the funds to our general partner and another subsidiary of Petrohawk as partial consideration for the partnership properties contributed to us;

• the entrance by us into an administrative services agreement with Petrohawk, HK Management and our general partner pursuant to which we will reimburse Petrohawk and its affiliates $5.7 million in allocated general and administrative costs, including $2.8 million in incremental costs related to being a publicly traded partnership.

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The unaudited pro forma balance sheet assumes the transactions listed above occurred on June 30, 2007. The summary pro forma financial data is derived from pro forma financial statements of HK Energy Partners LP included elsewhere in this prospectus.

You should read the following table in conjunction with “ — Formation Transactions and Partnership Structure,” “Use of Proceeds,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” the historical carve out financial statements of HK Energy Partners LP Predecessor, and the unaudited pro forma financial statements of HK Energy Partners LP included elsewhere in this prospectus. Among other things, those historical and pro forma financial statements include more detailed information regarding the basis of presentation for the following information.

The following table presents summary historical financial information for HK Energy Partners LP Predecessor as well as summary pro forma data for HK Energy Partners LP. Also included in this table is a non-GAAP financial measure, Adjusted EBITDA, which we use in our business. This measure is not calculated or presented in accordance with accounting principles generally accepted in the United States of America (“GAAP”). We explain this measure below and reconcile it to the most directly comparable financial measures calculated and presented in accordance with GAAP.

	HK Energy Partners LP Predecessor									Pro Forma HK Energy Partners LP
	Year Ended December 31, 2006			Six Months Ended June 30,						Year Ended December 31, 2006			Six Months Ended June 30, 2007
				2006			2007
	(in thousands except per unit data)
Operating revenues:
Oil and natural gas	$	59,578		$	22,225		$	37,272		$	78,285		$	37,272
Operating expenses:
Production:
Lease operating		8,694			3,550			5,536			10,328			5,536
Workover and other		198			9			38			247			38
Taxes other than income		5,606			1,727			3,664			7,467			3,664
Gathering, transportation and other		878			158			824			1,483			824
Impairment expense		53,190			—			—			53,190			—
General and administrative		4,683			1,711			2,873			5,723			2,861
Depletion, depreciation and amortization		23,740			7,052			13,034			30,617			13,034
Total operating expenses		96,989			14,207			25,969			109,055			25,957
(Loss) income from operations		(37,411	)		8,018			11,303			(30,770	)		11,315
Interest expense and other		(18,953	)		(7,442	)		(11,882	)		(5,042	)		(2,521	)
(Loss) income before income taxes	$	(56,364	)	$	576		$	(579	)	$	(35,812	)	$	8,794
Income tax provision		(714	)		(576	)		(50	)		(714	)		(50	)
Net (loss) income	$	(57,078	)	$	—		$	(629	)	$	(36,526	)	$	8,744
Pro forma net (loss) income per limited partner unit										$	(2.36	)	$	0.57
Adjusted EBITDA	$	39,519		$	15,070		$	24,337		$	53,037		$	24,349
Balance sheet data (at period end):
Working capital													$	171,747
Total assets														766,940
Long-term debt														223,120
Owner’s equity														531,513
Cash flow data:
Net cash provided by (used in):
Operating activities	$	15,292		$	7,223		$	11,306
Investing activities		(311,683	)		(6,311	)		(8,532	)
Financing activities		296,391			(912	)		(2,774	)

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Adjusted EBITDA

We use EBITDA, adjusted as described below, which we refer to in this prospectus as Adjusted EBITDA, as a supplemental measure of our performance that is not required by, or presented in accordance with, GAAP. We define Adjusted EBITDA as net income plus (i) impairment expense, (ii) depletion, depreciation, and amortization, (iii) interest expense and other and (iv) income taxes. We present Adjusted EBITDA because we consider it an important supplemental measure of our performance, and in particular because it excludes amounts that do not relate directly to our operating performance. Because the use of Adjusted EBITDA facilitates comparisons of our historical operating performance on a more consistent basis, we use this measure for business planning and analysis purposes, in assessing acquisition opportunities and in determining how potential external financing sources are likely to evaluate our business.

Adjusted EBITDA is not a measurement of our financial performance under GAAP and should not be considered as an alternative to net income, operating income or any other performance measure derived in accordance with GAAP, as an alternative to cash flow from operating activities or as a measure of our liquidity. You should not assume that the Adjusted EBITDA amounts shown in this prospectus are comparable to Adjusted EBITDA amounts disclosed by other companies. In evaluating Adjusted EBITDA, you should be aware that it excludes expenses that we will incur in the future on a recurring basis.

Adjusted EBITDA has limitations as an analytical tool, and you should not consider it in isolation. Some of its limitations are:

• it does not reflect our cash expenditures for capital expenditures;

• it does not reflect our interest expense, or the cash requirements necessary to service interest or principal payments on our indebtedness; and

• although depletion, depreciation, and amortization are non-cash charges, the assets being depreciated and amortized will often have to be replaced in the future, and Adjusted EBITDA does not reflect the cost or cash requirements for such replacements.

We compensate for these limitations by relying primarily on our GAAP results and using Adjusted EBITDA only supplementally. For more information, see our combined financial statements and the notes to those statements included elsewhere in this prospectus. The following table reconciles our net income before income taxes to our Adjusted EBITDA on a historical and pro forma basis as of the dates shown (in thousands):

	HK Energy Partners LP Predecessor								Pro Forma HK Energy Partners LP
	Year Ended December 31, 2006			Six Months Ended June 30,					Year Ended December 31, 2006			Six Months Ended June 30, 2007
				2006		2007
	(in thousands)
Net (loss) income	$	(57,078	)	$	—	$	(629	)	$	(36,526	)	$	8,744
Impairment expense		53,190			—		—			53,190			—
Depletion, depreciation and amortization		23,740			7,052		13,034			30,617			13,034
Interest expense and other		18,953			7,442		11,882			5,042			2,521
Income tax provision		714			576		50			714			50
Adjusted EBITDA	$	39,519		$	15,070	$	24,337		$	53,037		$	24,349

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Summary Reserve and Operating Data

The following tables show our estimated net proved oil and natural gas reserves based on reserve reports prepared by NSAI, our independent petroleum engineers, and certain summary unaudited information regarding production and sales of oil and natural gas with respect to such properties. You should refer to “Risk Factors,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Business — Oil and Natural Gas Data — Oil and Natural Gas Reserves” in evaluating the material presented below.

	December 31, 2006(1)		June 30, 2007(1)
Reserve Data:
Estimated net proved reserves:
Oil (MMBbls)	6.8		6.8
Natural gas (Bcf)(2)	107.7		104.7
Total (Bcfe)	148.6		145.3
Proved developed (Bcfe)	119.6		115.4
Proved undeveloped (Bcfe)	29.0		29.9
Proved developed reserves as % of total estimated net proved reserves	80	%	79	%
% Natural gas(2)	72	%	72	%

(1) Our estimates of proved reserves have been made in accordance with SEC guidelines using constant oil and natural gas prices and operating costs at the date indicated and are based on the December 31, 2006 West Texas Intermediate posted price of $57.75 per Bbl of oil and Henry Hub spot market price of $5.63 per MMBtu of gas and the June 30, 2007 West Texas Intermediate posted price of $67.25 per Bbl of oil and Henry Hub spot market price of $6.80 per MMBtu of gas.

(2) Includes NGL volumes calculated using natural gas equivalents of six Mcf of natural gas per Bbl of oil or NGL.

	Year Ended December 31, 2006				Six Months Ended June 30, 2007
	HK Energy Partners LP		HK Energy Partners LP		HK Energy Partners LP
	Predecessor		Pro Forma(1)		Pro Forma(1)
Production:
Oil (MBbl)		356		361		171
Natural gas (MMcf)(2)		5,646		7,951		3,746
Total production (MMcfe)		7,780		10,116		4,772
Average daily production (MMcfe/d)		21.3		27.7		26.3
Average price per unit (excluding hedges):
Oil (per Bbl)	$	58.95	$	59.03	$	54.88
Gas (per Mcf)		6.72		7.08		7.38
Average cost per Mcfe:
Lease operating expenses	$	1.12	$	1.02	$	1.16
Other operating expenses(3)		0.14		0.17		0.18
Taxes other than income		0.72		0.74		0.77

(1) The unaudited pro forma combined statements of operations gives effect to the formation of the partnership, the contribution to the partnership by affiliates of Petrohawk of all of the partnership properties, and certain other transactions as if they had occurred on January 1, 2006.

(2) Includes NGL volumes calculated using natural gas equivalents of six Mcf of natural gas per Bbl of NGL.

(3) Includes workover and gathering, transportation and other expenses.

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RISK FACTORS

Limited partner interests are inherently different from capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in similar businesses. You should consider carefully the following risk factors together with all of the other information included in this prospectus in evaluating an investment in our common units.

If any of the following risks were actually to occur, our business, financial condition or results of operations could be materially adversely affected. In that case, we might not be able to pay the minimum quarterly distribution on our common units, the trading price of our common units could decline and you could lose all or part of your investment.

Risks Related to Our Business

We may not have sufficient cash flow from operations to pay the minimum quarterly distribution on our common units following establishment of cash reserves and payment of fees and expenses, including reimbursement of expenses to our general partner and Petrohawk.

Our pro forma cash available for distribution for the year ended December 31, 2006 and the twelve months ended June 30, 2007, would have been sufficient to pay only 44% and 84%, respectively, of the minimum quarterly distributions on our common units for those periods. To make our cash distributions at our minimum quarterly distribution rate of $0.35 per common unit per quarter, or $1.40 per unit per year, we will require available cash of approximately $7.3 million per quarter, or $29.1 million per year, based on the total common and subordinated units and general partner interests outstanding immediately after completion of this offering. We may not have sufficient available cash from operating surplus each quarter to enable us to make cash distributions at the minimum quarterly distribution rate under our cash distribution policy. The amount of cash we can distribute on our common units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:

• the amount of oil and natural gas we produce;

• the prices at which we sell our oil and natural gas production;

• our ability to acquire additional oil and natural gas properties at economically attractive prices;

• cash settlement of hedging positions;

• the amount of cash reserves, which we expect to be substantial, established by our general partner for the proper conduct of our business and for capital expenditures to maintain our production levels over the long-term;

• the level of our operating and administrative costs;

• the level of our interest expense, which depends on the amount of our indebtedness and the interest payable thereon; and

• timing and collectibility of receivables.

In addition, the actual amount of cash we will have available for distribution will depend on other factors, some of which are beyond our control, including:

• the level of competition we face;

• government regulation and taxation;

• fluctuations in our working capital needs;

• our ability to borrow funds and access capital markets; and

• prevailing economic conditions.

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As a result of these factors, the amount of cash we distribute to our common unitholders may fluctuate significantly from quarter to quarter and may be less than the minimum quarterly distribution amount that we expect to distribute. For a description of additional restrictions and factors that may affect our ability to make cash distributions, see “Our Cash Distribution Policy and Restrictions on Distributions.”

The amount of cash we have available for distribution to holders of our common units depends primarily on our cash flow.

You should be aware that the amount of cash we have available for distribution depends primarily upon our cash flow, including financial reserves, working capital or other borrowing, and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record losses for financial accounting purposes and may not make cash distributions during periods when we record net income for financial accounting purposes.

Our estimate of the minimum Adjusted EBITDA necessary for us to make a distribution on all units at the minimum quarterly distribution rate for each of the four quarters ending December 31, 2008 is based on assumptions that are inherently uncertain and are subject to significant business, economic, financial, legal, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those estimated.

Our estimate of the minimum Adjusted EBITDA necessary for us to make a distribution on all units at the minimum quarterly distribution rate for each of the four quarters ending December 31, 2008, as set forth in “Our Cash Distribution Policy and Restrictions on Distributions,” is based on our management’s calculations, and we have not received an opinion or report on it from any independent accountants. This estimate is based on assumptions about development activities, production, oil and natural gas prices, settlements under commodity derivative contracts, capital expenditures, expenses, borrowings and other matters that are inherently uncertain and are subject to significant business, economic, financial, legal, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those estimated. If any of these assumptions prove to have been inaccurate, our actual results may differ materially from those set forth in our estimates, and we may be unable to pay all or part of the minimum quarterly distribution on our common units.

If oil or natural gas prices decline significantly, our cash flow from operations will decline and we may have to lower our distributions or may not be able to pay distributions at all.

Our revenue, profitability and cash flow depend upon the prices for oil and natural gas. The prices we receive for oil and natural gas production are volatile and a drop in prices can significantly affect our financial results and impede our growth, including our ability to maintain or increase our borrowing capacity, to repay current or future indebtedness and to obtain additional capital on attractive terms, all of which can affect our ability to pay distributions. Changes in oil and natural gas prices have a significant impact on the value of our reserves and on our cash flow. Prices for oil and natural gas may fluctuate widely in response to relatively minor changes in the supply and demand, market uncertainty and a variety of additional factors that are beyond our control, such as:

• the domestic and foreign supply of oil and natural gas;

• the ability of members of the Organization of Petroleum Exporting Countries, or OPEC, and other producing countries to agree upon and maintain 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;

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

• the price and availability of alternative fuels;

• the price of foreign imports; and

• worldwide economic conditions.

In the past, the prices of oil and natural gas have been extremely volatile, and we expect this volatility to continue. For example, during the year ended December 31, 2006, the NYMEX oil price ranged from a high of $77.03 per Bbl to a low of $55.81 per Bbl. During 2006, the NYMEX Henry Hub natural gas price ranged from a high of $9.87 per MMBtu to a low of $3.63 per MMBtu. NYMEX closing oil and natural gas prices at December 31, 2006 were $57.75 per Bbl of oil and $5.63 per MMBtu of natural gas. At June 30, 2007, the NYMEX closing oil price had increased from December 31, 2006 to $70.68 per Bbl, while the NYMEX closing natural gas price had increased to $6.77 per MMBtu. At October 15, 2007, the NYMEX closing oil and natural gas prices for 2008 were $81.02 per Bbl of oil and $8.15 per MMBtu of natural gas. These volatile changes, particularly in natural gas prices, will also correspondingly affect the standardized measure of discounted future net cash flows of our net estimated proved reserves.

Lower oil or gas prices may not only decrease our revenues, but also reduce the amount of oil or gas that we can produce economically. This may result in our having to make substantial downward adjustments to our estimated proved reserves. If this occurs, or if our estimates of development costs increase, production data factors change or drilling results deteriorate, accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties for impairments. We are required to perform impairment tests on our assets whenever events or changes in circumstances lead to a reduction of the estimated useful life or estimated future cash flows that would indicate that the carry amount may not be recoverable or whenever management’s plans change with respect to those assets. We may incur impairment charges in the future, which could have a material adverse effect on our results of operations in the period taken and our ability to borrow funds under our credit facility, which may adversely affect our ability to make cash distributions to our unitholders.

Our credit facility will likely contain substantial restrictions and financial covenants that may restrict our business and financing activities and our ability to pay distributions.

The credit facility that we expect to enter into upon the closing of this offering, and any future financing agreements that we may enter into, will likely contain operating and financial restrictions and covenants that may restrict our ability to finance future operations or capital needs or to engage, expand or pursue our business activities or to pay distributions. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Capital Resources and Liquidity — Credit Facility.”

Our ability to comply with the restrictions and covenants in our credit facility in the future is uncertain and will be affected by the levels of cash flow from our operations and events or circumstances beyond our control. If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired. If we violate any of the restrictions, covenants, ratios or tests in our credit facility, a significant portion of our indebtedness may become immediately due and payable, our ability to make distributions will be inhibited and our lenders’ commitment to make further loans to us may terminate. We might not have, or be able to obtain, sufficient funds to make these accelerated payments. In addition, our obligations under our credit facility will be secured by substantially all of our assets, and if we are unable to repay our indebtedness under our credit facility, the lenders could seek to foreclose on our assets.

Our credit facility will likely limit the amounts we can borrow to a borrowing base amount, to be determined by the lenders in their sole discretion. Outstanding borrowings in excess of the borrowing base will be required to be repaid immediately, or we will be required to pledge other oil and natural gas properties as additional collateral.

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Unless we replace the oil and natural gas reserves we produce, our revenues and production will decline, which would adversely affect our cash flow from operations and our ability to make distributions to our unitholders.

Producing reservoirs are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Based on our June 30, 2007 reserve report, our average annual estimated decline rate for estimated net proved developed producing reserves is 9.4% during the first five years, 7.3% in the next five years and less than 7.2% thereafter. This rate of decline is an estimate, and actual production declines could be materially higher. Our decline rate may change when we drill additional wells, make acquisitions and under other circumstances. Our future cash flow and income and our ability to maintain and to increase distributions to unitholders are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find or acquire additional reserves to replace our current and future production at acceptable costs, which would adversely affect our business, financial condition and results of operations. Factors that may hinder our ability to acquire additional reserves include competition, access to capital, prevailing oil and natural gas prices and the number and attractiveness of properties for sale.

The estimated oil and natural gas reserve quantities and future production rates set forth in this prospectus are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or the underlying assumptions will materially affect the quantities and present value of our reserves.

Numerous uncertainties are inherent in estimating quantities of oil and natural gas reserves. This prospectus contains estimates of our pro forma net proved reserve quantities. These estimates are based upon reports of NSAI, our independent petroleum engineers. The process of estimating oil and natural gas reserves is complex, requiring significant decisions and assumptions in the evaluation of available geological, engineering and economic data for each reservoir, and these reports rely upon various assumptions, including assumptions regarding future oil and natural gas prices, production levels, and operating and development costs. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may prove to be inaccurate. Over time, we may make material changes to reserve estimates taking into account the results of actual drilling and production. Any significant variance from our assumptions by actual results could greatly affect our estimates of reserves, the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery, and estimates of the future net cash flows.

The standardized measure of discounted future net cash flows of our actual and pro forma estimated net proved reserves is not necessarily the same as the current market value of our estimated net proved reserves. We base the discounted future net cash flows from our estimated net proved reserves on prices and costs in effect on the day of the estimate. Actual prices received for production and actual costs of such production will be different than these assumptions, perhaps materially.

The timing of both our production and our incurrence of expenses in connection with the development and production of our properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general. Any material inaccuracy in our reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves which could adversely affect our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.

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Our development operations will require substantial capital expenditures, which will reduce our cash available for distribution. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a decline in our production and reserves.

The oil and natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures in our business for the development, production and acquisition of oil and natural gas reserves. These expenditures will be deducted from our revenues in determining our cash available for distribution. We intend to finance our future capital expenditures with cash flow from operations, borrowings under our credit facility that we expect to enter into at the consummation of this offering and the issuance of debt and equity securities. The incurrence of debt will require that a portion of our cash flow from operations be used for the payment of interest and principal on our debt, thereby reducing our ability to use cash flow to fund working capital, capital expenditures and acquisitions. Our cash flow from operations and access to capital are subject to a number of variables, including:

• the estimated quantities of our oil and natural gas reserves;

• changes in oil and natural gas prices;

• changes in labor and drilling costs;

• the amount of oil and natural gas we produce from existing wells;

• the prices at which we sell our production;

• our ability to acquire, locate and produce new reserves; and

• government regulations relating to safety and the environment.

If our revenues or the borrowing base under our credit facility decrease as a result of lower commodity prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. Our credit facility may restrict our ability to obtain new financing. If additional capital is needed, we may not be able to obtain debt or equity financing on terms favorable to us, or at all. If cash generated by operations or available under our credit facility is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our prospects, which in turn could lead to a possible decline in our reserves and production, which could lead to a decline in our oil and natural gas reserves, and could adversely effect our business, results of operation, financial conditions and ability to make distributions to you. In addition, we may lose opportunities to acquire oil and natural gas properties and businesses.

We may incur substantial debt in the future to enable us to maintain or increase our production levels and to otherwise pursue our business plan. This debt may restrict our ability to make distributions.

Our business requires a significant amount of capital expenditures to maintain and grow our production levels. If prices were to decline for an extended period of time, if the costs of our acquisition and development operations were to increase substantially, or if other events were to occur which reduced our revenues or increased our costs, we may be required to borrow significant amounts in the future to enable us to finance the expenditures necessary to replace the reserves we produce. The cost of the borrowings and our obligations to repay the borrowings could have important consequences to us, including:

• our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;

• covenants contained in our existing and future credit and debt arrangements will require us to meet financial tests that may affect our flexibility in planning for and reacting to changes in our business, including possible acquisition opportunities;

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• we will need a substantial portion of our cash flow to make principal and interest payments on our indebtedness, reducing the funds that would otherwise be available for operations, future business opportunities and distributions to unitholders; and

• our debt level will make us more vulnerable than our competitors with less debt to competitive pressures or a downturn in our business or the economy generally.

Our ability to service our indebtedness will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying business activities, acquisitions, investments and/or capital expenditures, selling assets, restructuring or refinancing our indebtedness, or seeking additional equity capital or bankruptcy protection. We may not be able to effect any of these remedies on satisfactory terms or at all.

Shortages of drilling rigs, equipment and crews could delay our operations and reduce our cash available for distribution.

Prolonged higher oil and natural gas prices typically result in increased demand for drilling rigs, equipment and crews and can lead to shortages of, and increasing costs for, drilling equipment, services and personnel. Shortages of, or increasing costs for, experienced drilling crews and oil field equipment and services could restrict our ability to drill the wells and conduct the operations which we currently have planned. Any delay in the drilling of new wells or significant increase in drilling costs could reduce our revenues and cash available for distribution.

We will rely on development drilling to replace production. If our development drilling is unsuccessful, our cash available for distributions and our financial condition will be adversely effected.

Part of our business strategy will focus on replacing production by drilling development wells. Although Petrohawk and its affiliates have been successful in development drilling in the past, we cannot assure you that we will continue to replace production through development drilling. Our drilling involves numerous risks, including the risk that we will not encounter commercially productive oil or natural gas reservoirs. We must incur significant expenditures to drill and complete wells. Additionally, seismic technology does not allow us to know conclusively, prior to drilling a well, that oil or natural gas is present or economically producible. The costs of drilling and completing wells are often uncertain, and it is possible that we will make substantial expenditures on development drilling and not discover reserves in commercially viable quantities. These expenditures will reduce cash available for distribution to our unitholders.

Our drilling operations may be curtailed, delayed or cancelled as a result of a variety of factors, including:

• unexpected drilling conditions;

• facility or equipment failure or accidents;

• shortages or delays in the availability of drilling rigs and equipment;

• adverse weather conditions;

• compliance with environmental and governmental requirements;

• title problems;

• unusual or unexpected geological formations;

• pipeline ruptures;

• fires, blowouts, craterings and explosions; and

• uncontrollable flows of oil or gas or well fluids.

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Secondary and tertiary recovery techniques may not be successful, which could adversely affect our financial condition or results of operations and, as a result, our ability to pay distributions to our unitholders.

Approximately 12% of our production and 17% of our reserves as of June 30, 2007 rely on secondary and tertiary recovery techniques, which include waterfloods and injecting natural gases into producing formations to enhance hydrocarbon recovery. If production response is less than forecast for a particular project, then the project may be uneconomic or generate less cash flow and reserves than we had estimated prior to investing capital. Risks associated with secondary and tertiary recovery techniques include, but are not limited to, the following:

• lower-than-expected production;

• longer response times;

• higher capital costs;

• shortages of equipment; and

• lack of technical expertise.

If any of these risks occur, it could adversely affect our financial condition or results of operations and, as a result, our ability to pay distributions to our unitholders.

If we do not make acquisitions on economically acceptable terms, our future growth and ability to pay or increase distributions will be limited.

Our ability to grow and to increase distributions to unitholders depends in part on our ability to make acquisitions that result in an increase in pro forma available cash per unit. We may be unable to make such acquisitions because we are:

• unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them;

• unable to obtain financing for these acquisitions on economically acceptable terms; or

• outbid by competitors.

If we are unable to acquire properties containing proved reserves, our total level of proved reserves will decline as a result of our production, and we will be limited in our ability to increase or possibly even to maintain our level of cash distributions.

Any acquisitions we complete are subject to substantial risks that could reduce our ability to make distributions to unitholders.

Even if we do make acquisitions that we believe will increase pro forma available cash per unit, these acquisitions may nevertheless result in a decrease in pro forma available cash per unit. Any acquisition involves potential risks, including, among other things:

• the validity of our assumptions about reserves, future production, revenues, capital expenditures, operating expenses and costs, including synergies;

• an inability to integrate the businesses we acquire successfully;

• a decrease in our liquidity by using a significant portion of our available cash or borrowing capacity to finance acquisitions;

• a significant increase in our interest expense or financial leverage if we incur additional debt to finance acquisitions;

• the assumption of unknown liabilities, losses or costs for which we are not indemnified or for which our indemnity is inadequate;

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• the diversion of management’s attention from other business concerns;

• an inability to hire, train or retain qualified personnel to manage and operate our growing business and assets;

• natural disasters;

• the incurrence of other significant charges, such as impairment of goodwill or other intangible assets, asset devaluation or restructuring charges;

• unforeseen difficulties encountered in operating in new geographic areas; and

• customer or key employee losses at the acquired businesses.

Our decision to acquire a property will depend in part on the evaluation of data obtained from production reports and engineering studies, geophysical and geological analyses and seismic and other information, the results of which are often inconclusive and subject to various interpretations.

Also, our reviews of acquired properties are inherently incomplete because it generally is not feasible to perform an in-depth review of the individual properties involved in each acquisition given time constraints imposed by sellers. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential. Inspections may not always be performed on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken.

Our hedging activities could result in financial losses or could reduce our net income, which may adversely affect our ability to pay distributions to our unitholders.

To achieve more predictable cash flow and to reduce our exposure to adverse fluctuations in the prices of oil and natural gas, we currently and may in the future enter into derivative arrangements for a significant portion of our oil and natural gas production. Such arrangements could result in both realized and unrealized commodity derivative losses. Moreover, while hedging can prevent losses when market prices are less than the fixed prices provided in the derivative instruments, we will not benefit from hedged production when market prices are higher than the fixed prices provided in the derivative instruments. The extent of our commodity price exposure is related largely to the effectiveness and scope of our derivative activities. For example, the derivative instruments we utilize are based on posted market prices, which may differ significantly from the actual natural gas and crude oil prices we realize in our operations. Furthermore, our revolving credit facility requires that we limit derivative transactions that cap the price we will receive from expected production volumes and, as a result, we will continue to have direct commodity price exposure on a portion of our production volumes. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — How We Evaluate Our Operations — Derivative Instruments and Hedging Activities.”

Our actual future production may be significantly higher or lower than we estimate at the time we enter into derivative transactions for such period. If the actual amount is higher than we estimate, we will have greater commodity price exposure than we intended. If the actual amount is lower than the nominal amount that is subject to our derivative financial instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of the cash flow from our sale or purchase of the underlying physical commodity, resulting in a substantial diminution of our liquidity. As a result of these factors, our derivative activities may not be as effective as we intend in reducing the volatility of our cash flows, and in certain circumstances may actually increase the volatility of our cash flows. In addition, our derivative activities are subject to the following risks:

• a counterparty may not perform its obligation under the applicable derivative instrument;

• there may be a change in the expected differential between the underlying commodity price in the derivative instrument and the actual price received, which may result in payments to our derivative counterparty that are not accompanied by our receipt of higher prices from our production in the field; and

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• federal agencies that oversee energy commodity markets may view certain hedging activities, especially in conjunction with purchases and sales in physical markets for energy commodities, as potential violations of laws and regulations prohibiting market manipulation.

An increase in the differential between NYMEX or other benchmark prices of oil and natural gas and the reference or regional index price used to price our actual oil and natural gas sales could have a material adverse effect on our results of operations and financial condition and our ability to make distributions to our unitholders.

Our oil and natural gas production is priced in the local markets where the production occurs. Pricing can be influenced by local or regional supply and demand factors. Numerous factors may influence local pricing, such as refinery capacity, pipeline capacity and specifications, upsets in the midstream or downstream sectors of the industry, trade restrictions and governmental regulations. During the year ended December 31, 2006 and the twelve months ended June 30, 2007, our average wellhead price differential to NYMEX prices was approximately 90% for oil and 98% and 104%, respectively, for natural gas. We may be adversely impacted by an increase in the price differential from NYMEX on the oil and natural gas we sell. Our current hedging arrangements and those we intend to enter into pursuant to our hedging policy will be based on West Texas Intermediate oil or Henry Hub natural gas index prices, so we may be subject to basis risk if the differential on the production we sell increases from those benchmarks, unless we have a contract tied to those benchmarks. Additionally, insufficient pipeline capacity, lack of demand in any given operating area or other factors may cause the deferential to increase in that area compared with other producing areas. In the future, any sales interruptions related to these or other issues could result in similar increases in commodity differentials, which would have a material adverse effect on our results of operations and financial condition and would impair our ability to make cash distributions.

We may not be able to compete effectively with larger companies, which may adversely affect our ability to generate sufficient revenue and our ability to pay distributions to our unitholders.

The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources than us. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Many of our larger competitors not only drill for and produce oil and natural gas, but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for natural gas properties and evaluate, bid for and purchase a greater number of properties than our financial or human resources permit. In addition, these companies may have a greater ability to continue drilling activities during periods of low oil and natural gas prices, to contract for drilling equipment, to secure trained personnel, and to absorb the burden of present and future federal, state, local and other laws and regulations. The oil and natural gas industry has periodically experienced shortages of drilling rigs, equipment, pipe and personnel, which have delayed development drilling and other exploitation activities and have caused significant price increases. Competition has been strong in hiring experienced personnel, particularly in the accounting and financial reporting, tax and land departments. In addition, competition is strong for attractive oil and natural gas producing properties, oil and natural gas companies, and undeveloped leases and drilling rights. We may be outbid by competitors in our attempts to acquire properties or companies. Our inability to compete effectively with larger companies could have a material adverse impact on our business activities, financial condition and results of operations.

Our business is subject to operational risks that will not be fully insured, which, if they were to occur, could adversely affect our financial condition or results of operations and, as a result, our ability to pay distributions to our unitholders.

Our business activities are subject to operational risks, including:

• facility or equipment malfunctions;

• damages to equipment caused by adverse weather conditions;

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• fires, blowouts, craterings and explosions; and

• uncontrollable flows of oil or gas or well fluids.

Any of these events could adversely affect our ability to conduct operations or cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution or other environmental contamination, loss of wells, regulatory penalties, suspension of operations, and attorney’s fees and other expenses incurred in the prosecution or defense of litigation.

As is customary in the industry, we maintain insurance against some but not all of these risks. Additionally, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses could therefore occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance or a prolonged delay in the payment of insurance proceeds could have a material adverse impact on our business activities, financial condition, results of operations and ability to make distributions to our unitholders.

Our business depends in part on gathering and transportation facilities owned by others. Any limitation in the availability of those facilities could interfere with our ability to market our oil and natural gas production and could harm our business.

The marketability of our oil and natural gas production depends in part on the availability, proximity and capacity of pipelines, oil and natural gas gathering systems and processing facilities. The amount of oil and natural gas that can be produced and sold is subject to curtailment in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, pressure problems, non-compliance with quality specifications, physical damage or lack of available capacity on such systems. The curtailments arising from these and similar circumstances may last from a few days to several months. In many cases, we are provided only with limited, if any, notice as to when these circumstances will arise and their duration. It is also possible that pipelines and gathering facilities through which our production is transported may be abandoned, converted to other use or otherwise permanently rendered unavailable. Any significant curtailment in gathering system or pipeline capacity could reduce our ability to market our oil and natural gas production and harm our business.

We have limited control over the activities on properties that Petrohawk does not operate.

As of June 30, 2007, companies other than Petrohawk operated approximately 49% of our properties (measured by total estimated proved reserves). We have limited ability to influence or control the operation or future development of these non-operated properties or the amount of capital expenditures that we are required to fund with respect to them. Our dependence on the operator and other working interest owners for these projects and our limited ability to influence or control the operation and future development of these properties could materially adversely affect the realization of our targeted returns on capital in drilling or acquisition activities and lead to unexpected future costs.

We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations.

Our oil and natural gas exploration, production and marketing operations are subject to complex and stringent laws and regulations. In order to conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities. Failure or delay in obtaining regulatory approvals or drilling permits could have a material adverse effect on our ability to develop our properties, and receipt of drilling permits with onerous conditions could increase our compliance costs. In addition, laws and regulations regarding conservation practices and the protection of correlative rights affect our operations by, among other things, limiting the quantity of natural gas and oil we may produce and sell, and the location and spacing of wells.

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We are subject to federal, state and local laws and regulations as interpreted and enforced by governmental authorities possessing jurisdiction over various aspects of the exploration, production and sale of natural gas and oil. While the cost of compliance with these laws has not been material to our operations in the past, the possibility exists that new laws, regulations or enforcement policies could be more stringent and significantly increase our compliance costs. If we are not able to recover the resulting costs through insurance or increased revenues, our ability to pay distributions to our unitholders could be adversely affected. See “Business — Environmental Matters and Regulation” for more information.

Our operations expose us to significant costs and liabilities with respect to environmental and operational safety matters.

We may incur significant costs and liabilities as a result of environmental and safety requirements applicable to our oil and natural gas exploration and production operations. These costs and liabilities could arise under a wide range of federal, state and local environmental and safety laws and regulations, including regulations and enforcement policies, which have tended to become increasingly strict over time. There is an inherent risk that we may incur environmental costs and liabilities due to the nature of our business and the substances that we handle.

Failure to comply with environmental laws and regulations could result in the assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs and liens, and to a lesser extent, issuance of orders to limit or cease certain operations. In addition, certain environmental laws impose strict, joint and several liability, which could cause us to become liable for the conduct of others or for consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for damages as a result of environmental and other impacts. See “Business — Environmental Matters and Regulation” for more information.

We depend on certain key customers for sales of our oil and natural gas. We may experience a temporary decline in revenues and production if we lose one of our significant customers.

During 2006, Shell Trading Company, Southern Gas Services, Ltd., DCP Midstream Partners LP, Enterprise Products Partners LP and ConocoPhillips each accounted for more than 10% of our natural gas and oil revenues. In 2006, our top five customers accounted for approximately 67% of our natural gas and oil revenues. To the extent any of these significant customers reduces the volume of its oil or gas purchases from us, we could experience a temporary interruption in sales of, or a lower price for, our oil and natural gas production and our revenues and cash available for distribution could decline which could adversely affect our ability to make cash distributions to our unitholders.

Due to our lack of asset and geographic diversification, adverse developments in our operating areas would reduce our ability to make distributions to our unitholders.

We only own oil and natural gas properties and related assets. Our properties are primarily located in the Permian Basin region in West Texas and southeastern New Mexico. As a result, our business is disproportionately exposed to adverse developments affecting this region. These potential adverse developments could result from, among other things, changes in governmental regulation, capacity constraints with respect to the pipelines or gathering systems connected to our wells, curtailment of production, natural disasters or adverse weather conditions in or affecting this region. Due to our lack of diversification in asset type and location, an adverse development in the oil and natural gas business of these geographic areas would have a significantly greater impact on our results of operations and cash available for distribution to our unitholders than if we maintained more diverse assets and locations.

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Risks Inherent in an Investment in Us

Petrohawk and its affiliates own a controlling interest in us and may have conflicts of interest with us and limited fiduciary duties to us, which may permit them to favor their own interests to your detriment.

Following the offering, Petrohawk and its affiliates will own 55.4% of our aggregate outstanding common and subordinated units and general partner interests, and they will control our general partner, which controls us. The directors and officers of HK Management, the general partner of our general partner, have a fiduciary duty to manage our general partner in a manner beneficial to Petrohawk. Furthermore, certain directors and officers of HK Management will be directors or officers of affiliates of our general partner, including Petrohawk. Conflicts of interest may arise between Petrohawk and its affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand. As a result of these conflicts, our general partner may favor its own interests and the interests of its affiliates over the interests of our public unitholders. See “— Our partnership agreement limits our general partner’s fiduciary duties to holders of our common units and subordinated units” and “Our partnership agreement restricts the remedies available to holders of our common units and subordinated units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.” These potential conflicts include, among others, the following situations:

• neither our partnership agreement nor any other agreement requires Petrohawk or its affiliates (other than our general partner) to pursue a business strategy that favors us. Petrohawk’s directors and officers have a fiduciary duty to make these decisions in the best interests of its shareholders, which may be contrary to our interests;

• our general partner is allowed to take into account the interests of parties other than us, such as Petrohawk and its affiliates, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to our unitholders;

• Petrohawk is not limited in its ability to compete with us and is under no obligation to offer assets to us. In addition, Petrohawk may compete with us with respect to any future acquisition opportunities. See “— Petrohawk is not limited in its ability to compete with us, which could limit our ability to acquire additional assets or businesses”;

• some officers of our general partner who will provide services to us will devote time to affiliates of our general partner and may be compensated for services rendered to those affiliates;

• our general partner determines the amount and timing of our drilling program and related capital expenditures, asset purchases and sales, borrowings, issuance of additional partnership securities and reserves, each of which can affect the amount of cash that is distributed to unitholders;

• our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf;

• our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates; and

• our general partner decides whether to retain separate counsel, accountants or others to perform services for us.

See “Conflicts of Interest and Fiduciary Duties.”

Petrohawk is not limited in its ability to compete with us, which could limit our ability to acquire additional assets or businesses.

Neither our partnership agreement nor the administrative services agreement we will enter into with Petrohawk and HK Management upon the closing of this offering prohibits Petrohawk from owning assets or engaging in businesses that compete directly or indirectly with us. In addition, Petrohawk may acquire, develop

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or dispose of additional oil and natural gas properties or other assets in the future, without any obligation to offer us the opportunity to purchase or develop any of those assets. Petrohawk is a large, established participant in the oil and natural gas industry, and has significantly greater resources and experience than we have, which factors may make it more difficult for us to compete with Petrohawk with respect to commercial activities as well as for acquisition candidates. As a result, competition from Petrohawk could adversely impact our results of operations and cash available for distribution. See “Conflicts of Interest and Fiduciary Duties.”

We do not have any employees and rely solely on officers and employees of HK Management, a wholly owned subsidiary of Petrohawk. Failure of such officers and employees to devote sufficient attention to the management and operation of our business may adversely affect our financial results and our ability to make distributions to our unitholders.

We do not have any employees and are managed solely by our general partner, which is managed by HK Management. We intend to enter into an administrative services agreement with HK Management and Petrohawk pursuant to which Petrohawk and its affiliates will perform administrative services for us, such as accounting, corporate development, finance, land, legal and engineering and we will reimburse Petrohawk and its affiliates for such services based upon the good faith determination of our general partner of the expenses allocable to us. We will also reimburse actual third-party expenses incurred on our behalf. Petrohawk will have substantial discretion in determining which third-party expenses to incur on our behalf. We will also pay our share of expenses that are directly chargeable to wells under joint operating agreements. Petrohawk and its affiliates conduct businesses and activities of their own in which we have no economic interest. These separate activities are significantly greater than our activities, and could be material competition for the time and effort of the officers and employees of HK Management who provide services to our general partner, on the one hand, and to, Petrohawk and its affiliates, on the other. If these officers and employees of HK Management do not devote sufficient attention to the management and operation of our business, our financial results may suffer and our ability to make distributions to our unitholders may be reduced.

We intend to rely upon Petrohawk to execute our drilling program. If Petrohawk fails to or inadequately performs, our operations will be disrupted and our costs could increase or our reserves may not be developed, reducing our future levels of production and our cash from operations, which could affect our ability to make cash distributions.

In connection with the closing of this offering, we will enter into a contract operating agreement with a subsidiary of Petrohawk pursuant to which such subsidiary will be the operator of all of our existing producing wells and will coordinate our development drilling program. Under the agreement, the subsidiary will advise and consult with us regarding all aspects of our production and development operations. If Petrohawk fails to or inadequately performs these functions, our operations will be disrupted and our costs could increase or our reserves may not be developed or properly developed, reducing our future levels of production and our cash from operations, which could affect our ability to make distributions to you.

Cost reimbursements due to our general partner and its affiliates for services provided may be substantial and could reduce our cash available for distribution to you.

Pursuant to an administrative services agreement we will enter into with Petrohawk and HK Management upon the closing of this offering, Petrohawk will receive reimbursement for the provision of various general and administrative services for our benefit. In addition, we will enter into a contract operating agreement with another subsidiary of Petrohawk pursuant to which the subsidiary will be the operator of all of the wells for which we have the right to appoint an operator. Payments for these services will be substantial and will reduce the amount of cash available for distribution to unitholders. See “Certain Relationships and Related Transactions — Administrative Services Agreement” and “Business — Well Operations.” In addition, under Delaware partnership law, our general partner has unlimited liability for our obligations, such as our debts and environmental liabilities, except for our contractual obligations that are expressly made without recourse to our

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general partner. To the extent our general partner incurs obligations on our behalf, we are obligated to reimburse or indemnify it. If we are unable or unwilling to reimburse or indemnify our general partner, our general partner may take actions to cause us to make payments of these obligations and liabilities. Any such payments could reduce the amount of cash otherwise available for distribution to our unitholders.

Our partnership agreement limits our general partner’s fiduciary duties to holders of our common units and subordinated units.

Although our general partner has a fiduciary duty to manage us in a manner beneficial to us and our unitholders, the directors and officers of HK Management, the general partner of our general partner, have a fiduciary duty to manage our general partner in a manner beneficial to its owners. Our partnership agreement contains provisions that reduce the standards to which our general partner and its affiliates would otherwise be held by state fiduciary duty laws. For example, our partnership agreement permits our general partner and its affiliates to make a number of decisions either in their individual capacities, as opposed to in the capacity as our general partner, or otherwise free of fiduciary duties to us and our unitholders. This entitles our general partner and its affiliates to consider only the interests and factors that they desire, and they have no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include:

• whether or not to exercise the general partner’s right to reset the target distribution levels of its incentive distribution rights at higher levels and receive, in connection with this reset, a number of Class B units that are convertible at any time following the first anniversary of the issuance of these Class B units into common units;

• whether or not to exercise its limited call right;

• how to exercise its voting rights with respect to the units it owns;

• whether or not to exercise its registration rights; and

• whether or not to consent to any merger or consolidation of the partnership or amendment to the partnership agreement.

By purchasing a common unit, a common unitholder will agree to become bound by the provisions in the partnership agreement, including the provisions discussed above. See “Conflicts of Interest and Fiduciary Duties — Fiduciary Duties.”

Our partnership agreement restricts the remedies available to holders of our common units and subordinated units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

Our partnership agreement contains provisions restricting the remedies available to unitholders for actions taken by our general partner or its affiliates that might otherwise constitute breaches of fiduciary duty. For example, our partnership agreement provides that:

• our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as it acted in good faith, meaning it believed the decision was in the best interests of our partnership;

• affiliated transactions and resolutions of conflicts of interest not approved by the conflicts committee of the board of directors of HK Management and not involving a vote of unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or must be “fair and reasonable” to us, as determined by our general partner in good faith and that, in determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us; and

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• our general partner and the officers and directors of HK Management will not be liable for monetary damages to us, our limited partners or assignees for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the general partner or those other persons acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal.

See “Conflicts of Interest and Fiduciary Duties — Fiduciary Duties.”

Our general partner may elect to cause us to issue Class B units to it in connection with a resetting of the target distribution levels related to our general partner’s incentive distribution rights without the approval of the conflicts committee of HK Management or holders of our common units and subordinated units. This may result in lower distributions to holders of our common units in certain situations.

Our general partner has the right, at a time when there are no subordinated units outstanding and it has received incentive distributions at the highest level to which it is entitled (23%) for each of the prior four consecutive fiscal quarters, to reset the initial cash target distribution levels at higher levels based on the distribution at the time of the exercise of the reset election. Following a reset election by our general partner, the minimum quarterly distribution amount will be reset to an amount equal to the average cash distribution amount per common unit for the two fiscal quarters immediately preceding the reset election (such amount is referred to as the “reset minimum quarterly distribution”) and the target distribution levels will be reset to correspondingly higher levels based on the same percentage increases above the reset minimum quarterly distribution amount as in our current target distribution levels.

In connection with resetting these target distribution levels, our general partner will be entitled to receive a number of Class B units. The Class B units will be entitled to the same cash distributions per unit as our common units and will be convertible into an equal number of common units. The number of Class B units to be issued will be equal to that number of common units whose aggregate quarterly cash distributions equaled the average of the distributions to our general partner on the incentive distribution rights in the prior two quarters. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion; however, it is possible that our general partner could exercise this reset election at a time when it is experiencing, or may be expected to experience, declines in the cash distributions it receives related to its incentive distribution rights and may therefore desire to be issued our Class B units, which are entitled to receive cash distributions from us on the same priority as our common units, rather than retain the right to receive incentive distributions based on the initial target distribution levels. As a result, a reset election may cause our common unitholders to experience dilution in the amount of cash distributions that they would have otherwise received had we not issued new Class B units to our general partner in connection with resetting the target distribution levels related to our general partner incentive distribution rights. See “How We Will Make Cash Distributions — General Partner’s Right to Reset Target Distribution Levels.”

Holders of our common units have limited voting rights and are not entitled to elect our general partner or the board of directors of its general partner.

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders will not elect our general partner, its general partner or the members of its board of directors, and will have no right to elect our general partner, its general partner or its board of directors on an annual or other continuing basis. The board of directors of HK Management will be chosen by Petrohawk, the sole member of HK Management. Furthermore, if the unitholders were dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.

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Even if holders of our common units are dissatisfied, they cannot initially remove our general partner without its consent.

The unitholders will be unable initially to remove our general partner without its consent because our general partner and its affiliates will own sufficient units upon completion of this offering to be able to prevent its removal. The vote of the holders of at least 66 ²/3% of all outstanding units voting together as a single class is required to remove the general partner. Following the closing of this offering, our general partner and its owners and their affiliates will own 55.4% of our aggregate outstanding common and subordinated units and general partner interests. Also, if our general partner is removed without cause during the subordination period and units held by our general partner and its affiliates are not voted in favor of that removal, all remaining subordinated units will automatically convert into common units and any existing arrearages on our common units will be extinguished. A removal of our general partner under these circumstances would adversely affect our common units by prematurely eliminating their distribution and liquidation preference over our subordinated units, which would otherwise have continued until we had met certain distribution and performance tests. Cause is narrowly defined to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding the general partner liable for actual fraud or willful or wanton misconduct in its capacity as our general partner. Cause does not include most cases of charges of poor business management, so the removal of the general partner because of the unitholder’s dissatisfaction with our general partner’s performance in managing our partnership will most likely result in the termination of the subordination period and conversion of all subordinated units to common units.

Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units.

Unitholders’ voting rights are further restricted by the partnership agreement provision providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot vote on any matter. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.

Control of our general partner may be transferred to a third party without unitholder consent.

Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, our partnership agreement does not restrict the ability of the owners of our general partner or HK Management, from transferring all or a portion of their respective ownership interest in our general partner or HK Management to a third party. The new owners of our general partner or HK Management would then be in a position to replace the board of directors and officers of HK Management with its own choices and thereby influence the decisions taken by the board of directors and officers.

You will experience immediate dilution of $1.83 in tangible net book value per common unit.

The assumed initial public offering price of $20.00 per unit exceeds our pro forma net tangible book value of $18.17 per unit. Therefore, you will incur immediate dilution of $1.83 per common unit. This dilution results primarily because the assets contributed by our general partner and its affiliates are recorded in accordance with GAAP at their historical cost, and not their fair value. See “Dilution.”

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We may issue additional common units without your approval, which would dilute your existing ownership interests.

Our partnership agreement does not limit the number of additional limited partner interests that we may issue at any time without the approval of our unitholders. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:

• our unitholders’ proportionate ownership interest in us will decrease;

• the amount of cash available for distribution on each unit may decrease;

• because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;

• the ratio of taxable income to distributions may increase;

• the relative voting strength of each previously outstanding unit may be diminished; and

• the market price of the common units may decline.

Petrohawk and its affiliates may sell common units in the public markets, which sales could have an adverse impact on the trading price of the common units.

After the sale of the common units offered hereby, Petrohawk and its affiliates will hold an aggregate of 5,904,048 common units and 5,189,742 subordinated units. All of the subordinated units will convert into common units at the end of the subordination period. The sale of these common units in the public markets could have an adverse impact on the price of the common units or on any trading market that may develop.

We have the right to borrow to make distributions. Repayment of these borrowings will decrease cash available for future distributions, and covenants in our credit facility may restrict our ability to make distributions.

Our partnership agreement allows us to borrow to make distributions. We may make short term borrowings under our credit facility, which we refer to as working capital borrowings, to make distributions. The primary purpose of these borrowings would be to mitigate the effects of short term fluctuation in our working capital that would otherwise cause volatility in our quarter to quarter distributions.

The terms of our credit facility may restrict our ability to pay distributions if we do not satisfy the financial and other covenants in the facility.

Our partnership agreement requires that we distribute all of our available cash, which could limit our ability to grow our reserves and production.

Our partnership agreement provides that we will distribute all of our available cash each quarter. As a result, we will be dependent on the issuance of additional common units and other partnership securities and borrowings to finance our growth. A number of factors will affect our ability to issue securities and borrow money to finance growth, as well as the costs of such financings, including:

• general economic and market conditions, including interest rates, prevailing at the time we desire to issue securities or borrow funds;

• conditions in the oil and natural gas industry;

• the market price of, and demand for, our common units;

• our results of operations and financial condition; and

• prices for oil and natural gas.

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Our general partner has a limited call right that may require you to sell your units at an undesirable time or price.

If at any time our general partner and its affiliates own more than 80% of the common units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than their then-current market price. As a result, you may be required to sell your common units at an undesirable time or price and may not receive any return on your investment. You may also incur a tax liability upon a sale of your units. At the completion of this offering and assuming no exercise of the underwriters’ option to purchase additional common units, Petrohawk and its affiliates will own approximately 39% of our outstanding common units. At the end of the subordination period, assuming no additional issuances of common units and that all of the subordinated units are converted into common units, Petrohawk and its affiliates will own approximately 55% of our aggregate outstanding common units. For additional information about this right, see “The Partnership Agreement — Limited Call Right.”

An increase in interest rates may cause the market price of our common units to decline.

Like all equity investments, an investment in our common units is subject to certain risks. In exchange for accepting these risks, investors may expect to receive a higher rate of return than would otherwise be obtainable from lower-risk investments. Accordingly, as interest rates rise, the ability of investors to obtain higher risk-adjusted rates of return by purchasing government-backed debt securities may cause a corresponding decline in demand for riskier investments generally, including yield-based equity investments such as publicly traded limited partnership interests. Reduced demand for our common units resulting from investors seeking other more favorable investment opportunities may cause the trading price of our common units to decline.

Your liability may not be limited if a court finds that unitholder action constitutes control of our business.

A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. You could be liable for any and all of our obligations as if you were a general partner if:

• a court or government agency determined that we were conducting business in a state but had not complied with that particular state’s partnership statute; or

• your right to act with other unitholders to remove or replace the general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute “control” of our business.

For a discussion of the implications of the limitations of liability on a unitholder, see “The Partnership Agreement — Limited Liability.”

You may have liability to repay distributions that were wrongfully distributed to you.

Under certain circumstances, you may have to repay amounts wrongfully returned or distributed to you. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to you if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Substituted limited partners are liable for the obligations of the assignor to make contributions to the partnership that are known to the substituted limited partner at the time

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it became a limited partner and for unknown obligations if the liabilities could be determined from the partnership agreement. Liabilities to partners on account of their partnership interest and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.

We will incur increased costs as a result of being an independent publicly-traded company.

We have no history operating as an independent publicly-traded company. As a publicly-traded company, we will incur significant legal, accounting and other expenses that we did not incur as a private company. In addition, the Sarbanes-Oxley Act of 2002, as well as rules subsequently implemented by the SEC and the NYSE, require that we adhere to certain internal controls and corporate governance practices. We expect these rules and regulations to increase our legal and financial compliance costs and to make activities more time-consuming and costly. For example, as a result of becoming a publicly-traded company, HK Management is required to have at least three independent directors, create additional board committees and adopt policies regarding internal controls and disclosure controls and procedures, including the preparation of reports on internal controls over financial reporting. In addition, we will incur additional costs associated with our publicly-traded company reporting requirements. We also expect these new rules and regulations to make it more difficult and more expensive for HK Management to obtain director and officer liability insurance and it may be required to accept reduced policy limits and coverage or incur substantially higher costs to obtain the same or similar coverage. As a result, it may be more difficult for HK Management to attract and retain qualified persons to serve on its board of directors or as executive officers. We have included $2.8 million of estimated incremental costs per year associated with being an independent publicly-traded company for purposes of our financial forecast included elsewhere in this prospectus; however, it is possible that our actual incremental costs of being a publicly-traded company will be higher than we currently estimate.

You may have limited liquidity for your units, a trading market may not develop for the units and you may not be able to resell your units at the initial public offering price.

Prior to the offering, there has been no public market for the units. After the offering, there will be 9,250,000 publicly traded common units. We do not know the extent to which investor interest will lead to the development of a trading market or how liquid that market might be. You may not be able to resell your units at or above the initial public offering price. Additionally, the lack of liquidity may result in wide bid-ask spreads, contribute to significant fluctuations in the market price of the units and limit the number of investors who are able to buy the units.

In addition, trading markets may experience periods of volatility, which could result in highly variable and unpredictable pricing of securities. The market price of our common units could change in ways that may or may not be related to our business, our industry or our operating performance and financial condition.

If we fail to develop or maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, current and potential unitholders could lose confidence in our financial reporting, which would harm our business and the trading price of our common units.

Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a public company. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed. We cannot be certain that our efforts to develop and maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002. Any failure to develop or maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our common units.

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Tax Risks to Common Unitholders

In addition to reading the following risk factors, you should read “Material Tax Consequences” for a more complete discussion of the expected material federal income tax consequences of owning and disposing of common units.

Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service were to treat us as a corporation for federal income tax purposes or we were to become subject to additional entity-level taxation for state tax purposes, then our cash available for distribution would be substantially reduced.

The anticipated after-tax economic benefit of an investment in the common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the Internal Revenue Service, which we refer to as the IRS, on this or any other tax matter affecting us.

Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. Although we do not believe based upon our current operations that we will be treated as a corporation for federal income tax purposes, a change in our business (or a change in current law) could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35% and would likely pay state income tax at varying rates. Distributions to you would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to you. Because a tax would be imposed upon us as a corporation, our cash available for distribution to you would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to the unitholders, likely causing a substantial reduction in the value of our common units.

Current law may change so as to cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to entity-level taxation. For example, legislation has been proposed that would eliminate partnership tax treatment for certain publicly traded partnerships. Although such legislation would not apply to us as currently proposed, it could be amended prior to enactment in a manner that does apply to us. We are unable to predict whether any of these changes or other proposals will ultimately be enacted. Any such changes could negatively impact the value of an investment in our units.

In addition, because of widespread state budget deficits and other reasons, several states, including Texas, are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise, margin and other forms of taxation. For example, beginning in 2008, we will be subject to a new entity level tax on the portion of our income that is generated in Texas. Specifically, the Texas margin tax will be imposed at a maximum effective rate of 0.7% of our gross income that is apportioned to Texas. Imposition of such a tax on us by Texas, or any other state, will reduce the cash available for distribution to you.

Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to additional amounts of entity-level taxation, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.

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We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first business day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first business day of each month, instead of on the basis of the date a particular unit is transferred. The use of this method may not be permitted under existing Treasury regulations, and, accordingly, our counsel is unable to opine as to the validity of this method. If the IRS were to challenge this method or new Treasury regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders. See “Material Tax Consequences — Disposition of Units — Tax Allocations Between Transferors and Transferees.”

An IRS contest of our federal income tax positions may adversely affect the market for our common units, and the cost of any IRS contest will reduce our cash available for distribution to our unitholders

We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the conclusions of our counsel expressed in this prospectus or from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel’s conclusions or the positions we take. A court may not agree with all of our counsel’s conclusions or positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner because the costs will reduce our cash available for distribution.

You may be required to pay taxes on income from us even though your cash distributions from us are less than your share of income.

Because our unitholders will be treated as partners to whom we will allocate taxable income which could be different in amount than the cash we distribute, you may be required to pay any federal income taxes and, in some cases, state and local income taxes, on your share of our taxable income even if you receive no cash distributions from us. You may not receive cash distributions from us equal to your share of our taxable income or even equal to the tax liability that results from that income.

Tax gain or loss on disposition of common units could be more or less than expected.

If you sell your common units, you will recognize a gain or loss equal to the difference between the amount realized and your tax basis in those common units. Because distributions in excess of your allocable share of our net taxable income decrease your tax basis in your common units, the amount, if any, of such prior excess distributions with respect to the common units you sell will, in effect, become taxable income to you if you sell such units at a price greater than your tax basis in those units, even if the price you receive is less than your original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depletion, intangible drilling costs and depreciation recapture. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if you sell your common units, you may incur a tax liability in excess of the amount of cash you receive from the sale. See “Material Tax Consequences — Disposition of Units — Recognition of Taxable Gain or Loss” for a further discussion of the foregoing.

Tax-exempt entities and non-U.S. persons face unique tax issues from owning common units that may result in adverse tax consequences to them.

Investment in common units by tax-exempt entities, such as individual retirement accounts (known as IRAs), other retirement plans and non-U.S. persons raises issues unique to them. For example, virtually all of our

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income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file United States federal tax returns and pay tax on their share of our taxable income. If you are a tax-exempt entity or a non-U.S. person, you should consult your tax advisor before investing in our common units.

We will treat each purchaser of our common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.

Because we cannot match transferors and transferees of common units and because of other reasons, we will take depletion, depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to you. It also could affect the timing of these tax benefits or the amount of gain from the sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to your tax returns. For a further discussion of the effect of the depreciation and amortization positions we will adopt, see “Material Tax Consequences — Tax Consequences of Unit Ownership — Section 754 Election.”

The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.

We will be considered to have terminated our partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. For example, an exchange of 50% of our capital and profits could occur if, in any twelve-month period, holders of our subordinated and common units sell at least 50% of the interests in our capital and profits. Our termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and unitholders receiving two Schedule K-1s for one fiscal year). Our termination could also result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but instead, we would be treated as a new partnership for tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred. See “Material Tax Consequences — Disposition of Units — Constructive Termination” for a discussion of the consequences of our termination for federal income tax purposes.

Unitholders may be subject to state and local taxes and tax return filing requirements in states where they do not live as a result of investing in our common units.

In addition to federal income taxes, you will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or own property now or in the future, even if you do not live in any of those jurisdictions. You will likely be required to file foreign, state and local income tax returns and pay state and local income taxes in some or all of these jurisdictions. Further, you may be subject to penalties for failure to comply with those requirements. We will initially own assets and do business in Texas, New Mexico and Oklahoma. New Mexico and Oklahoma currently impose a personal income tax. As we make acquisitions or expand our business, we may own assets or do business in additional states that impose a personal income tax or that impose entity level taxes to which we could be subject. It is your responsibility to file all United States federal, foreign, state and local tax returns. Our counsel has not rendered an opinion on the foreign, state or local tax consequences of an investment in the common units.

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A unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of those units. If so, he would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.

Because a unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of the loaned units, he may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Thompson & Knight LLP has not rendered an opinion regarding the treatment of a unitholder where common units are loaned to a short seller to cover a short sale of common units; therefore, unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from loaning their units.

We may adopt certain valuation methodologies that may result in a shift of income, gain, loss and deduction between the general partner and the unitholders. The IRS may successfully challenge this treatment, which could adversely affect the value of our common units.

When we issue additional units or engage in certain other transactions, we will determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and the holders of the incentive distribution rights. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and the general partner, which may be unfavorable to such unitholders. Moreover, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of income, gain, loss and deduction between the general partner and certain of our unitholders.

A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.

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FORWARD-LOOKING STATEMENTS

Some of the information in this prospectus may contain forward-looking statements. These statements can be identified by the use of forward-looking terminology including “may,” “believe,” “expect,” “anticipate,” “estimate,” “continue,” or other similar words. These statements discuss future expectations, contain projections of results of operations or of financial condition, or state other “forward-looking” information. These forward-looking statements involve risks and uncertainties. When considering these forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this prospectus. The following could cause our actual results to differ materially from those contained in any forward-looking statement:

• prices we receive for our oil and natural gas production;

• our ability to replace the reserves we produce through drilling and property acquisitions;

• our ability to attract capital; and

• the other matters discussed under “Risk Factors,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Business” and elsewhere in this prospectus.

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USE OF PROCEEDS

We expect to receive net proceeds of approximately $170.0 million from the sale of 9,250,000 common units offered by this prospectus, assuming an offering price of $20.00 per unit and after deducting underwriting discounts, a structuring fee and estimated offering expenses. Our estimates assume no exercise of the underwriters’ option to purchase additional common units. We anticipate using the aggregate net proceeds of this offering to:

• purchase approximately $165.0 million of qualifying investment grade securities, which will be assigned as collateral to secure the term loan portion of our credit facility; and

• fund $5.0 million of working capital.

A $1.00 increase or decrease in the assumed initial public offering price of $20.00 per common unit would cause the net proceeds from the offering, after deducting underwriting discounts, a structuring fee and estimated offering expenses, to increase or decrease by approximately $8.6 million.

We also anticipate that we will borrow approximately $58.1 million in revolving debt and $165.0 million in term debt upon the closing of this offering. The $165.0 million in term debt will be collateralized by $165.0 million of qualifying investment grade securities. We will distribute the aggregate amount of the net proceeds from these borrowings to our general partner and another subsidiary of Petrohawk, which distribution will be made in partial consideration of the assets contributed to us upon the closing of this offering. See “Certain Relationships and Related Transactions — Distributions and Payments to Our General Partner and its Affiliates.”

The qualifying securities we will purchase will be assigned as collateral to secure the term loan borrowings. The interest we receive from our ownership of these securities will partially offset our cost of borrowings under the credit facility. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Capital Resources and Liquidity.”

If the underwriters’ option to purchase additional common units is exercised in full, we will use the net proceeds of approximately $25.8 million (also assuming an offering price of $20.00 per unit) to repay a portion of our revolving debt under our credit facility.

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CAPITALIZATION

The following table shows:

• our cash, cash equivalents and qualifying investment grade securities and our capitalization, each as of June 30, 2007; and

• our pro forma capitalization as of June 30, 2007, as adjusted to reflect this offering, the other transactions described under “Prospectus Summary — Formation Transactions and Partnership Structure” and the application of the net proceeds we expect to receive from this offering and our borrowings as described under “Use of Proceeds.”

We derived this table from, and it should be read in conjunction with and is qualified in its entirety by reference to, the historical and pro forma financial statements and the accompanying notes included elsewhere in this prospectus. You should also read this table in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” For a description of the pro forma adjustments, see our unaudited pro forma balance sheet.

	As of June 30, 2007
	Historical		Pro Forma(1)
	(In thousands)
Cash, cash equivalents and qualifying investment grade securities	$	—	$	170,000	(2)
Long-term debt	$	269,625	$	223,120	(2)
Owner’s equity/Partner’s capital:
Owner’s net equity	$	317,552	$	132,342
Common units — public		—		168,991
Common units — Petrohawk		—		118,081
Subordinated units — Petrohawk		—		103,795
General partner interest		—		8,304
Total owners’ equity/partners’ capital	$	317,552	$	531,513
Total capitalization	$	587,177	$	754,633

(1) Assumes an initial public offering price of our common units of $20.00 per unit and reflects net proceeds of approximately $170.0 million, after deducting underwriting discounts, a structuring fee and estimated offering expenses, and the application of the net proceeds. A $1.00 increase or decrease in the assumed initial public offering price per common unit would increase or decrease, respectively, the net proceeds by approximately $8.6 million. The pro forma information presented above is illustrative only and following completion of this offering will be adjusted based on the actual initial public offering price and other terms of this offering determined at pricing.

(2) Our initial $165.0 million in term borrowings will be collateralized by an equal $165.0 million in qualifying investment grade securities. Amount is inclusive of $5 million of cash on hand at June 30, 2007 for general working capital purposes.

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DILUTION

Dilution is the amount by which the offering price paid by the purchasers of common units sold in this offering will exceed the pro forma net tangible book value per unit after the offering. On a pro forma basis as of June 30, 2007, after giving effect to the offering of common units and the application of the related net proceeds, and assuming the underwriters’ option to purchase additional common units is not exercised, our net tangible book value was $377.2 million, or $18.17 per common unit. Purchasers of common units in this offering will experience substantial and immediate dilution in net tangible book value per common unit for financial accounting purposes, as illustrated in the following table:

Assumed initial public offering price per common unit			$	20.00
Pro forma net tangible book value per common unit before the offering(1)	$	8.18
Increase in net tangible book value per common unit attributable to purchasers in the offering		9.99
Less: Pro forma net tangible book value per common unit after the offering(2)				18.17
Immediate dilution in tangible net book value per common unit to new investors			$	1.83

(1) Determined by dividing the number of units and general partner interests (5,904,048 common units, 5,189,742 subordinated units and 415,179 additional units equivalent to the general partner interests) to be issued to Petrohawk for its contribution of assets and liabilities to us into the net tangible book value of the contributed assets and liabilities.

(2) Determined by dividing the total number of units and general partner interests to be outstanding after the offering (15,154,048 common units, 5,189,742 subordinated units and 415,179 additional units equivalent to the general partner interests) and the application of the related net proceeds into our pro forma net tangible book value, after giving effect to the application of the expected net proceeds of the offering.

The following table sets forth the number of units and general partner interests that we will issue and the total consideration contributed to us by the owners of our predecessors and by the purchasers of common units in this offering upon consummation of the transactions contemplated in this prospectus, assuming the underwriters do not exercise their option to purchase additional common units:

	Units Acquired			Total Consideration
	Number	Percent		Amount		Percent
				(in thousands)
General partner and its affiliates(1)(2)	11,508,969	55	%	$	230,179	55	%
New investors	9,250,000	45	%		185,000	45	%
Total	20,758,969	100	%	$	415,179	100	%

(1) Upon the consummation of the transaction contemplated in this prospectus, our general partner, which will be owned by Petrohawk and its affiliates, will own a 2% general partner interest in us which equates to 415,179 additional units. Petrohawk and its affiliates will own an aggregate of 5,904,048 common units and 5,189,742 subordinated units.

(2) The assets contributed by our general partner and its affiliates were recorded at historical cost in accordance with GAAP. The total consideration provided by the affiliates of Petrohawk, as of June 30, 2007, is equal to the net tangible book value of such assets.

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OUR CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS

You should read the following discussion of our cash distribution policy in conjunction with specific assumptions included in this section. For more detailed information regarding the factors and assumptions upon which our cash distribution policy is based, please read “— Assumptions and Considerations” below. In addition, you should read “Forward-Looking Statements” and “Risk Factors” for information regarding statements that do not relate strictly to historical or current facts and certain risks inherent in our business.

For additional information regarding our historical and pro forma operating results, you should refer to our audited carve-out financial statements for the years ended December 31, 2004, 2005 and 2006 and our unaudited interim carve-out financial statements for the six months ended June 30, 2006 and 2007 and our unaudited pro forma combined financial statements for the year ended December 31, 2006 and as of and for the six months ended June 30, 2007, included elsewhere in this prospectus.

General

Rationale for Our Cash Distribution Policy. Our partnership agreement requires us to distribute all of our available cash quarterly. Our available cash is our cash on hand at the end of a quarter after the payment of our expenses and the establishment of reserves for future capital expenditures and operational needs, including cash from borrowings. We intend to fund a portion of our capital expenditures with additional borrowings or issuances of additional units. We may also borrow to make distributions to unitholders, for example, in circumstances where we believe that the distribution level is sustainable over the long term, but short-term factors have caused available cash from operations to be insufficient to pay the distribution at the current level. For example, because we intend to hedge a significant portion of our production, we may be required to pay the derivative counterparties the difference between the fixed price and the market price before we receive the proceeds from the sale of the hedged production. Our cash distribution policy reflects a basic judgment that our unitholders will be better served by us distributing our available cash, after expenses and reserves, rather than retaining it. Also, because we are not subject to an entity-level federal income tax, we have more cash to distribute to our unitholders than would be the case if we were subject to federal income tax. See “How We Will Make Cash Distributions — Distributions of Available Cash from Operating Surplus during the Subordination Period” and “— Distributions of Available Cash from Operating Surplus after the Subordination Period.”

Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy. There is no guarantee that our unitholders will receive quarterly distributions from us. Our distribution policy may be changed at any time and is subject to certain restrictions, including the following:

• We expect to enter into a credit facility concurrently with the completion of this offering. We expect that our cash distribution policy will be subject to restrictions on distributions under this credit facility. Specifically, we expect our credit facility to contain material financial tests, such as a leverage ratio, a current ratio and an interest coverage ratio, and covenants that we must satisfy. These financial tests and covenants are described in this prospectus under the caption “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Capital Resources and Liquidity — Credit Facility.” Should we be unable to satisfy these restrictions or if we are otherwise in default under our credit facility, we would be prohibited from making cash distributions to you notwithstanding our stated cash distribution policy.

• Our general partner will have the authority to establish cash reserves for the prudent conduct of our business and for future cash distributions to our unitholders, and the establishment of those reserves could result in a reduction in cash distributions to you from levels we currently anticipate pursuant to our stated distribution policy. Any determination to establish reserves made by our general partner in good faith will be binding on the unitholders. We intend to reserve a substantial portion of our cash generated from operations to fund our development and exploitation capital expenditures and to acquire additional oil and natural gas properties and related assets. Over a longer period of time, if we do not set

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aside sufficient cash reserves or make sufficient cash expenditures to maintain or grow our asset base, we will be unable to pay distributions at the current level from cash generated from operations and would therefore expect to reduce our distributions. We are unlikely to be able to sustain our current level of distributions without making accretive acquisitions or capital expenditures that maintain or grow our asset base. Decreases in commodity prices from current levels will also adversely affect our ability to pay distributions. If our asset base decreases and we do not reduce our distributions, a portion of the distributions may be considered a return of part of your investment in us as opposed to a return on your investment.

• While our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including the provisions requiring us to make cash distributions, may be amended. Although during the subordination period, with certain exceptions, our partnership agreement may not be amended without the approval of the public common unitholders, our partnership agreement can be amended with the approval of a majority of the outstanding common units and any Class B units issued upon the reset of target distribution levels, if any, voting as a single class (including common units held by Petrohawk and its affiliates) after the subordination period has ended.

• Even if our cash distribution policy is not modified or revoked, the amount of distributions we pay under our cash distribution policy and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement.

• We may lack sufficient cash to pay distributions to our unitholders due to a number of factors, including lower realized prices for our oil and natural gas, increases in our operating or general and administrative expenses, principal and interest payments on our outstanding debt, tax expenses, working capital requirements and anticipated cash needs.

• We have assumed that our operations will not be subject to federal income tax but that we will be subject to state entity level taxation as well as state severance taxes applicable to oil and gas production. Several states, including Texas, have adopted taxes on the income of limited partnerships. Because most of our oil and natural gas properties are located in Texas, we believe that the Texas entity-level tax will affect our distributions.

• Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets.

Our Ability to Grow is Dependent on Our Ability to Access External Expansion Capital. Our partnership agreement requires us to distribute all of our available cash to our unitholders on a quarterly basis. As a result, to the extent that our cash generated from operations and cash reserves are inadequate to fund capital expenditures after paying distributions to unitholders, then we expect that we will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. To the extent we are unable to finance growth through internal and external sources, our cash distribution policy will significantly impair our ability to grow. In addition, because we distribute all of our available cash, our growth may not be as fast as businesses that reinvest their available cash to expand ongoing operations. If we issue additional units to finance any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level, which in turn may impact the available cash that we have to distribute on each unit. There are no limitations in our partnership agreement and we expect no limitations under our new revolving credit facility on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which in turn may impact the available cash that we have to distribute to our unitholders.

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Our Minimum Quarterly Distribution Rate

Upon completion of this offering, the board of directors of HK Management, the general partner of our general partner, will adopt a policy pursuant to which we will declare a minimum quarterly distribution of $0.35 per unit per complete quarter, or $1.40 per unit per year, to be paid no later than 45 days after the end of each fiscal quarter (beginning with the quarter ending March 31, 2008) through the quarter ending December 31, 2008. This equates to an aggregate cash distribution of $7.3 million per quarter or $29.1 million per year if the underwriters do not exercise their option to purchase additional common units and $7.8 million per quarter or $31.0 million if the underwriters do exercise their option to purchase additional common units in full, in each case based on the assumed number of common units, subordinated units and related general partner interests outstanding immediately after completion of this offering. Our ability to make cash distributions at the minimum quarterly distribution rate pursuant to this policy will be subject to the factors described above under “— General — Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy.”

The table below sets forth the number of outstanding common units (assuming no exercise of the underwriters’ option to purchase additional common units), subordinated units and general partner interests upon the closing of this offering and the aggregate distribution amounts payable on such units for the periods indicated at our minimum quarterly distribution rate of $0.35 per common unit per quarter ($1.40 per common unit on an annualized basis). We have presented this information both with and without giving effect to the full exercise of the underwriters’ option to purchase additional common units.

	No Exercise of the Underwriters' Option to Purchase Additional Common Units					Full Exercise of the Underwriters' Option to Purchase Additional Common Units
	Number of Units	Distributions				Number of Units	Distributions
		One Quarter		Four Quarters			One Quarter		Four Quarters
Publicly held common units	9,250,000	$	3,237,500	$	12,950,000	10,637,500	$	3,723,125	$	14,892,500
Common units beneficially owned by Petrohawk	5,904,048		2,066,417		8,265,667	5,904,048		2,066,417		8,265,667
Total	15,154,048	$	5,303,917	$	21,215,667	16,541,548	$	5,789,542	$	23,158,167
Subordinated units beneficially owned by Petrohawk	5,189,742		1,816,410		7,265,639	5,189,742		1,816,410		7,265,639
General partner interests held by our general partner	415,179		145,313		581,251	443,496		155,224		620,894
Total	20,758,969	$	7,265,640	$	29,062,557	22,174,786	$	7,761,176	$	31,044,700

As of the date of this offering, our general partner will be entitled to 2% of all distributions that we make prior to our liquidation. The general partner’s initial 2% interest in these distributions may be reduced if we issue additional units in the future and our general partner does not elect to contribute a proportionate amount of capital to us to maintain its initial 2% general partner interest.

The subordination period will generally end if we have earned and paid at least $1.40 (the minimum quarterly distribution on an annualized basis) on each outstanding common unit and subordinated unit and the related general partner’s 2% interest for any three consecutive non-overlapping four quarter periods ending on or after December 31, 2010. In addition, the subordination period will end if our general partner is removed without cause and the units held by our general partner and its affiliates are not voted in favor of such removal. When the subordination period ends, all remaining subordinated units will convert into an equal number of common units.

If distributions on our common units are not paid with respect to any fiscal quarter at the minimum quarterly distribution rate, our common unitholders will not be entitled to receive such payments in the future except that during the subordination period, to the extent we have available cash in any future quarter in excess of the amount necessary to make cash distributions to holders of our common units at the minimum quarterly

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distribution rate, we will use this excess available cash to pay these deficiencies related to prior quarters before any cash distribution is made to holders of subordinated units. See “How We Will Make Cash Distributions — Subordination Period.”

We do not have a legal obligation to pay distributions at our minimum quarterly distribution rate or at any other rate except as provided in our partnership agreement. Our distribution policy is consistent with the terms of our partnership agreement, which requires that we distribute all of our available cash quarterly. Under our partnership agreement, available cash is defined to generally mean, for each fiscal quarter, cash generated from our business in excess of the amount of reserves our general partner determines is necessary or appropriate to provide for the conduct of our business, to comply with applicable law, any of our debt instruments or other agreements or to provide for future distributions to our unitholders for any one or more of the upcoming four quarters.

Our partnership agreement provides that any determination made by our general partner in its capacity as our general partner must be made in good faith and that any such determination will not be subject to any other standard imposed by our partnership agreement, the Delaware limited partnership statute or any other law, rule or regulation or at equity. Holders of our common units may pursue judicial action to enforce provisions of our partnership agreement, including those related to requirements to make cash distributions as described above; however, our partnership agreement provides that our general partner is entitled to make the determinations described above without regard to any standard other than the requirements to act in good faith. Our partnership agreement provides that, in order for a determination by our general partner to be made in “good faith,” our general partner must believe that the determination is in our best interests.

Our cash distribution policy, as expressed in our partnership agreement, may not be modified or repealed without amending our partnership agreement; however, the actual amount of our cash distributions for any quarter is subject to fluctuations based on the amount of cash we generate from our business and the amount of reserves our general partner establishes in accordance with our partnership agreement as described above. During the subordination period, with certain exceptions, our partnership agreement may not be amended without the approval of the public common unitholders. After the subordination period has ended, our partnership agreement may be amended with the approval of our general partner and holders of a majority of our outstanding common units and any Class B units issued upon the reset of the target distribution levels, if any, voting together as a class (including common units held by Petrohawk and its affiliates).

We will pay our distributions on or about the 15th day of each of February, May, August and November to holders of record on or about the last day of the prior month. If the distribution date does not fall on a business day, we will make the distribution on the business day immediately preceding the indicated distribution date. We will adjust the quarterly distribution for the period from the closing of this offering through March 31, 2008 based on the actual length of the period.

Pro Forma Financial Information and Financial Forecast

You should read the following discussion of our cash distribution policy in conjunction with specific assumptions included in this section. For more detailed information regarding the factors and assumptions upon which our cash distribution policy is based, please read “— Assumptions and Considerations” below. In addition, you should read “Forward-Looking Statements” and “Risk Factors” for information regarding statements that do not relate strictly to historical or current facts and certain risks inherent in our business.

For additional information regarding our historical and pro forma operating results, you should refer to our historical financial statements as of December 31, 2005 and 2006 and for the years ended December 31, 2004, 2005 and 2006 and as of June 30, 2007 and for the six months ended June 30, 2006 and 2007. You should also refer to our unaudited pro forma financial statements for the year ended December 31, 2006 and as of and for the six months ended June 30, 2007. The full content of these financial statements is included elsewhere in this prospectus.

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In the sections that follow, we present in detail the basis for our belief that we will be able to fully fund our minimum quarterly distribution rate of $0.35 per unit each quarter through the quarter ending December 31, 2008. The following is a summary of the two tables that provide support to our conclusion:

• Our “Historical Pro Forma Available Cash,” in which we present the amount of cash we would have had available for the year ended December 31, 2006 and for the twelve months ended June 30, 2007 based on our unaudited pro forma financial statements. Our calculation of pro forma available cash in this table should only be viewed as a general indication of the amount of available cash that we might have generated had we been formed in 2006.

• Our “Estimated Cash Available for Distribution,” in which we present how we calculate the estimated minimum Adjusted EBITDA necessary for us to have sufficient cash available for distribution to pay the full minimum quarterly distribution on all outstanding units for the twelve months ending December 31, 2008. In “— Assumptions and Considerations” below, we also present our assumptions underlying our belief that we will generate sufficient Adjusted EBITDA to pay the minimum quarterly distribution on all outstanding units for twelve months ending December 31, 2008.

Unaudited Pro Forma Available Cash for the Year Ended December 31, 2006 and for the Twelve Months Ended June 30, 2007

If we had completed the transactions contemplated in this prospectus on January 1, 2006, our pro forma available cash for the year ended December 31, 2006 and for the twelve months ended June 30, 2007 would have been approximately $9.5 million and $18.3 million, respectively. The pro forma available cash would not have been sufficient to make the necessary cash distribution at the minimum distribution rate of $0.35 per unit per quarter (or $1.40 per unit on an annualized basis) on all of the common units, subordinated units and the related distributions on our general partner’s 2% general partner interest for the year ended December 31, 2006 and for the twelve months ended June 30, 2007 by approximately $19.6 million and $10.8 million, respectively.

For the year ended December 31, 2006, the pro forma available cash would have been sufficient to pay a cash distribution of $0.15 per unit per quarter ($0.61 per unit on an annualized basis), or approximately 44% of the minimum quarterly distribution. For the twelve months ended June 30, 2007, the pro forma available cash would have been sufficient to pay a cash distribution of $0.30 per unit per quarter ($1.18 per unit on an annualized basis), or approximately 84% of the minimum quarterly distribution. During neither time period would we have been able to pay any distributions on the subordinated units. Assuming the underwriters exercise in full their option to purchase additional common units, pro forma available cash would have fallen short of the amount necessary to make a cash distribution at the minimum distribution rate of $0.35 per unit per quarter (or $1.40 per unit on an annualized basis) on all of the common units, subordinated units and the related distributions on our general partner’s 2% general partner interest for the year ended December 31, 2006 and for the twelve months ended June 30, 2007 by approximately $19.7 million and $10.8 million, respectively. The tables below set forth pro forma estimated available cash per unit and the percentage of the minimum quarterly distribution represented thereby assuming no exercise and full exercise of the underwriters’ option to purchase additional units.

	No Exercise of the Underwriters’ Option to Purchase Additional Common Units
	Estimated Cash Available for Distribution
	Pro Forma for the Year Ended December 31, 2006			Pro Forma for the Twelve Months Ended June 30, 2007
Per unit distribution on common units	$	0.6111		$	1.1824
Per unit distribution on subordinated units		—			—
% of Minimum Quarterly Distribution on common units		43.7	%		84.5	%

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	Full Exercise of the Underwriters’ Option to Purchase Additional Common Units
	Estimated Cash Available for Distribution
	Pro Forma for the Year Ended December 31, 2006			Pro Forma for the Twelve Months Ended June 30, 2007
Per unit distribution on common units	$	0.6747		$	1.1980
Per unit distribution on subordinated units		—			—
% of Minimum Quarterly Distribution on common units		48.2	%		85.6	%

We based the pro forma adjustments upon currently available information and specific estimates and assumptions. The pro forma amounts below do not purport to present our results of operations had the transactions contemplated in this prospectus actually been completed as of the dates indicated. In addition, cash available to pay distributions is primarily a cash accounting concept, while our pro forma financial statements have been prepared on an accrual basis. As a result, you should view the amount of pro forma available cash only as a general indication of the amount of cash available to pay distributions that we might have generated had we been formed in an earlier period.

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The following table illustrates, on a pro forma basis, for the year ended December 31, 2006 and for the twelve months ended June 30, 2007, the amount of available cash that would have been available for distributions to our unitholders, assuming that the formation transactions and this offering occurred on January 1, 2006, and that the underwriters did not exercise their option to purchase additional common units. Each of the pro forma adjustments presented below is explained in the footnotes to such adjustments.

	Pro Forma Year Ended December 31, 2006			Pro Forma Twelve Months Ended June 30, 2007
	(In thousands, except per unit data)
Net loss	$	(36,526	)	$	(36,915	)
Plus:
Interest expense and other		5,042			5,042
Impairment expense		53,190			53,190
Depletion, depreciation and amortization expense		30,617			28,438
Income tax provision		714			188
Adjusted EBITDA(1)	$	53,037		$	49,943
Less:
Cash interest expense(2)		5,042			5,042
Capital expenditures(3)		32,822			20,894
Estimated general and administrative expenses(4)		5,723			5,723
Pro forma available cash	$	9,450		$	18,284
Distributions per unit	$	1.40		$	1.40
Pro forma cash distributions:
Distributions to our general partner	$	581		$	581
Distributions to public common unitholders		12,950			12,950
Distributions to common units held by our general partner and its affiliates		8,266			8,266
Distributions to subordinated units		7,266			7,266
Total distributions	$	29,063		$	29,063
Excess (Deficit)	$	(19,613	)	$	(10,779	)
Percent of minimum quarterly distribution payable to common unitholders		44	%		84	%
Percent of minimum quarterly distribution payable to subordinated unitholders		0	%		0	%

(1) See “Prospectus Summary — Summary Historical and Pro Forma Financial Data.”

(2) Reflects the interest expense related to $58.1 million in revolving debt under our credit facility at an assumed annual interest rate of 7.5% and $165.0 million in term debt at an assumed annual interest rate of 5.8% offset by $165.0 million of marketable securities at an assumed rate of 5.5% for the year ended December 31, 2006 and for the twelve months ended June 30, 2007, respectively. If the interest rate used to calculate this interest were 1.0% higher or lower, our annual cash interest cost would increase or decrease, respectively, by approximately $0.6 million.

(3) These amounts represent actual capital expenditures associated with the partnership properties for the year ended December 31, 2006 and for the twelve months ended June 30, 2007.

(4) Reflects estimated general and administrative expenses comprising expenses allocated to us by Petrohawk as well as an estimated $2.8 million of incremental expenses we expect to incur as a result of being a publicly traded partnership.

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The table below sets forth pro forma available cash, distributions per unit, pro forma cash distributions and the excess of our pro forma available cash for the periods indicated assuming full exercise of the underwriters’ option to purchase additional common units:

	Pro Forma Year Ended December 31, 2006			Pro Forma Twelve Months Ended June 30, 2007
	(In thousands)
Pro forma available cash	$	11,388		$	20,222
Distributions per unit	$	1.40		$	1.40
Pro forma cash distributions:
Distributions to our general partner	$	621		$	621
Distributions to public common unitholders		14,892			14,892
Distributions to common units held by our general partner and its affiliates		8,266			8,266
Distributions to subordinated units		7,266			7,266
Total distributions	$	31,045		$	31,045
Excess (Deficit)	$	(19,657	)	$	(10,823	)

Our cash interest expense for the year ended December 31, 2006 and the twelve months ended June 30, 2007 would decrease by $1.9 million for both periods due to the repayment of a portion of the borrowings under our revolving credit facility with the proceeds from the full exercise of the underwriters’ option to purchase additional common units.

Estimated Cash Available for Distribution for the Twelve Months Ending December 31, 2008

In order to pay the minimum quarterly distribution of $0.35 per unit on all our common units, subordinated units and the related distributions on our general partner’s 2% general partner interest for the twelve months ending December 31, 2008, we estimate that our Adjusted EBITDA for the twelve months ending December 31, 2008 must be at least $53.3 million. Adjusted EBITDA should not be considered an alternative to net income, operating income, cash flows from operating activities or any other measure of financial performance calculated in accordance with GAAP, as those items are used to measure our operating performance, liquidity or ability to service debt obligations. See “Prospectus Summary — Summary Historical and Pro Forma Financial Data” for an explanation of Adjusted EBITDA and reconciliations of Adjusted EBITDA to net income and net cash from operating activities, its most directly comparable financial performance and liquidity measures calculated in and presented in accordance with GAAP.

We also anticipate that if our Adjusted EBITDA for such period is at or above our estimate, we would be permitted to make the quarterly distributions on all the common units, subordinated units and the related distributions on our general partner’s 2% general partner interest at the minimum distribution rate under the applicable covenants under our revolving and term loan credit facility.

We believe that we will be able to generate the estimated minimum Adjusted EBITDA of $53.3 million for the twelve months ending December 31, 2008. You should read “— Assumptions and Considerations” below for a discussion of the material assumptions underlying this belief, which reflect our judgment of conditions we expect to exist and the course of action we expect to take. If our estimate is not achieved, we may not be able to pay the minimum quarterly distribution on all of our units. We can give you no assurance that our assumptions will be realized or that we will generate the $53.3 million in estimated minimum Adjusted EBITDA required to pay the initial minimum quarterly distribution on all our common units, subordinated units and the related distributions on our general partner’s 2% general partner interest. There will likely be differences between our

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estimates and the actual results we will achieve and those differences could be material. If we do not generate the estimated minimum Adjusted EBITDA or if our capital expenditures or interest expense are higher than estimated, we may not be able to pay the minimum quarterly distribution on all units.

Assuming the underwriters do not exercise their option to purchase additional common units, in order to fund distributions on all our common units, subordinated units and the related distributions on our general partner’s 2% general partner interest at the minimum distribution rate of $1.40 per unit for the twelve months ending December 31, 2008, we estimate that our minimum Adjusted EBITDA for the twelve months ending December 31, 2008 must be at least $53.3 million. Assuming the underwriters exercise in full their option to purchase additional common units, in order to fund distributions on all our common units, subordinated units and the related distributions on our general partner’s 2% general partner interest at the minimum distribution rate of $1.40 per unit for the twelve months ending December 31, 2008, we estimate that our minimum Adjusted EBITDA for the twelve months ending December 31, 2008 must be at least $53.4 million.

When considering our ability to generate sufficient estimated minimum Adjusted EBITDA to fund distributions on our common units, you should keep in mind the risk factors and other cautionary statements under the heading “Risk Factors” and elsewhere in this prospectus. Any of these factors or the other risks discussed in this prospectus could cause our results of operations and cash available for distribution to our unitholders to vary significantly from those set forth below.

We present below a financial forecast of the expected results of operations and cash flows for HK Energy Partners LP for the twelve months ending December 31, 2008. We do not as a matter of course make public projections as to future sales, earnings or other results. However, our management has prepared the prospective financial information set forth below to present the pro forma and forecasted results of operations and cash flows, forecasted production, price and drilling information and forecast of cash available for distribution for the twelve months ending December 31, 2008. The accompanying prospective financial information was not prepared with a view toward complying with the guidelines established by the American Institute of Certified Public Accountants with respect to prospective financial information, but, in the view of our management, was prepared on a reasonable basis, reflects the best currently available estimates and judgments and presents, to the best of our management’s knowledge and belief, the expected course of action and our expected future financial performance. However, this information is not fact and should not be relied upon as being necessarily indicative of future results, and readers of this prospectus are cautioned not to place undue reliance on the prospective financial information.

The assumptions and estimates underlying the financial forecast are inherently uncertain and, though considered reasonable by our management as of the date of its preparation, are subject to a wide variety of significant business, economic, and competitive risks and uncertainties that could cause actual results to differ materially from those contained in the financial forecast. Accordingly, there can be no assurance that the financial forecast results are indicative of the future performance of the partnership or that actual results will not differ materially from those presented in the financial forecast.

We do not undertake any obligation to release publicly the results of any future revisions we may make to the financial forecast or to update this financial forecast or the assumptions used to prepare the forecast to reflect events or circumstances after the date in this prospectus. In light of the above, the inclusion of the financial forecast and the statement that we believe that we will have sufficient cash available for distribution to allow us to make the full minimum quarterly distribution on all of our outstanding common units, subordinated units and the related distributions on our general partner’s 2% general partner interest for the twelve months ending December 31, 2008 should not be regarded as a representation by us or the underwriters or any other person that we will make such distributions. Therefore, you are cautioned not to place undue reliance on this information.

Neither HK Energy Partner LP’s independent registered public accounting firm, nor any other independent accountants, have compiled, examined or performed any procedures with respect to the prospective financial information contained herein, nor have they expressed any opinion or any other form of assurance on such information or its achievability, and they assume no responsibility for, and disclaim any association with, the prospective financial information, including the financial forecasts.

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The following table shows how we calculate the estimated minimum Adjusted EBITDA necessary to pay the minimum quarterly distribution on all our common units, subordinated units and the related distributions on our general partner’s 2% general partner interest for the twelve months ending December 31, 2008. Our estimated Adjusted EBITDA is based on the projected results of operations from all of our operating subsidiaries for the twelve months ending December 31, 2008 and assumes that the underwriters do not exercise their option to purchase additional common units. The assumptions that we have made that we believe are relevant to particular line items in the table below are explained in the corresponding footnotes set forth in “— Assumptions and Considerations.”

	Forecast for the Twelve Months Ending December 31, 2008
	(in thousands, except per unit data)
Operating Revenues:
Oil and natural gas revenues	$	79,693
Operating expenses:
Production:
Lease operations		10,721
Workover and other		188
Taxes other than income		7,467
Gathering, transportation and other		1,411
General and administrative		5,723
Depletion, depreciation and amortization		25,392
Total operating expenses:		50,902
Income from operations		28,791
Net gain on derivative contracts		3,514
Interest expense and other		(5,508	)
Net income before income taxes	$	26,797
Adjustments to reconcile net income before income taxes to estimated Adjusted EBITDA:
Add:
Depletion, depreciation and amortization expense	$	25,392
Interest expense and other		5,508
Estimated Adjusted EBITDA(1)	$	57,697
Adjustments to reconcile estimated Adjusted EBITDA to estimated cash available for distribution:
Less:
Cash interest expense	$	5,508
Estimated maintenance capital expenditures(2)		18,767
Estimated cash available for distribution	$	33,422
Total distributions for the period	$	29,063
Distributions to our general partner	$	581
Distributions on public common units		12,950
Distributions on common units held by our general partner and its affiliates		8,266
Distributions on subordinated units		7,266
Total distributions for the period	$	29,063
Excess of cash available for distribution over cash distributions for the period	$	4,359
Estimated Adjusted EBITDA	$	57,697
Less:
Excess of cash available for distribution over total cash distributions for the period		4,359
Minimum estimated Adjusted EBITDA necessary to pay minimum quarterly cash distributions for the period	$	53,338

(1) See “Prospectus Summary — Summary Historical and Pro Forma Financial Data.”

(2) Our estimated maintenance capital expenditures are those expenditures we believe are necessary to maintain our production and asset base over the long-term. In the forecast period we expect that the substantial majority of these expenditures will be made to develop our proved undeveloped reserves. In future years, we expect that our actual capital expenditures will consist of both development costs as well as expenditures necessary to acquire additional reserves. We plan to finance our acquisitions through a combination of internally generated cash flows and equity and debt issuances.

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The table below sets forth the estimated cash available for distribution, estimated Adjusted EBITDA and the minimum estimated Adjusted EBITDA necessary to pay cash distributions for the periods indicated assuming full exercise of the underwriters’ option to purchase additional common units:

	Twelve Months Ending December 31, 2008
	(in thousands, except per unit data)
Estimated cash available for distribution	$	35,360
Per unit cash distribution for the period	$	1.40
Distributions to our general partner	$	621
Distributions to public common unitholders		14,892
Distributions to common units held by our general partner and its affiliates		8,266
Distributions to subordinated units		7,266
Total distributions for the period	$	31,045
Excess of cash available for distribution over cash distributions for the period	$	4,315
Estimated Adjusted EBITDA	$	57,697
Less:
Excess of cash available for distribution over total cash distributions for the period		4,315
Minimum estimated Adjusted EBITDA necessary to pay minimum quarterly cash distributions for the period	$	53,382

Assuming full exercise of the underwriters’ option to purchase additional common units, our cash interest expense would decrease by $1.9 million for the twelve months ending December 31, 2008, due to repayment of a portion of the borrowings under our revolving credit facility with the proceeds from the full exercise of the underwriters’ option to purchase additional common units.

Assumptions and Considerations

Based upon the specific assumptions outlined below with respect to the twelve months ending December 31, 2008, we expect to generate cash flow from operations in an amount sufficient to fund our budgeted capital expenditures, establish adequate cash reserves to fund our anticipated maintenance capital expenditures and pay the minimum quarterly distribution on all of our outstanding common units and subordinated units and related distributions on our general partner’s 2% general partner interest through December 31, 2008.

While we believe that these assumptions are reasonable in light of management’s current expectations concerning future events, the estimates underlying these assumptions are inherently uncertain and are subject to significant business, economic, regulatory, environmental and competitive risks and uncertainties that could cause actual results to differ materially from those we anticipate. If our assumptions do not materialize, the amount of actual cash available to pay distributions could be substantially less than the amount we currently estimate and could, therefore, be insufficient to permit us to pay the full minimum quarterly distribution (absent borrowings under our revolving and term loan credit facility), or any amount, on all of our outstanding common units and subordinated units and the related distributions on our general partner’s 2% general partner interest, in which event the market price of our common units may decline substantially. We are unlikely to be able to sustain our current level of distributions without making accretive acquisitions or capital expenditures that maintain or grow our asset base. Over a longer period of time, if we do not set aside sufficient cash reserves or make sufficient cash expenditures to maintain or grow our asset base, we will be unable to pay distributions at the current level from cash generated from operations and would therefore expect to reduce our distributions. In addition, decreases in commodity prices from current levels will adversely affect our ability to pay distributions.

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If our asset base decreases and we do not reduce our distributions, a portion of the distribution may be considered a return of part of your investment in us as opposed to a return on your investment. When reading this section, you should keep in mind the risk factors and other cautionary statements under the headings “Risk Factors” and “Forward-Looking Statements.” Any of the risks discussed in this prospectus could cause our actual results to vary significantly from our estimates.

Operations and Revenue

Production. The following table sets forth information regarding net production of natural gas and oil on a pro forma basis for the twelve months ended December 31, 2006 and June 30, 2007 and on a forecasted basis for the twelve months ending December 31, 2008:

	Pro Forma for the Twelve Months Ended		Forecasted for the Twelve Months Ending December 31, 2008
	December 31, 2006	June 30, 2007
Oil production (MBbl)	361	351	331
Natural gas production (MMcf)(1)	7,951	7,742	7,417
Total production (MMcfe)	10,116	9,848	9,405
Average oil production (Bbl/d)	989	962	905
Average natural gas production (Mcf/d)	21,784	21,211	20,265
Total average production (MMcfe/d)	27.7	27.0	25.7

(1) Includes NGL volumes calculated using natural gas equivalents of six Mcf of natural gas per Bbl of oil or NGL.

We expect that our production will decrease for the twelve months ending December 31, 2008 as compared to the pro forma twelve months ended June 30, 2007. We intend to offset the natural decline in production by increased production as a result of development drilling and workover projects as well as reserve acquisitions in future periods.

We expect to drill 47 gross (12.1 net) wells during the twelve months ending December 31, 2008 to add production from our proved undeveloped reserves. All of the wells drilled and completed to date in 2007 are commercially productive. We have assumed that we will be successful in producing crude oil and natural gas in commercial quantities for all additional wells based on past drilling performance in our fields.

The forecast utilizes an assumed natural gas price of $7.75 per MMBtu and an assumed crude oil price of $75.00 per Bbl for the forecast period, as adjusted for average wellhead price differentials as well as our hedging program, as described in more detail below.

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Prices and Hedging. The table below illustrates the relationship between oil and natural gas wellhead prices as a percentage of average NYMEX prices and average realized prices including hedging on a pro forma basis for the twelve months ended December 31, 2006 and June 30, 2007 as compared to our forecast for the twelve months ending December 31, 2008:

	Pro Forma for the Twelve Months Ended						Forecasted for the Twelve Months Ending December 31, 2008
	December 31, 2006			June 30, 2007
Oil ($/Bbl):
Average NYMEX price	$	66.25		$	63.51		$	75.00
Average differential to NYMEX (excluding hedge impacts)		(7.22	)		(7.07	)		(7.50	)
Average wellhead price	$	59.03		$	56.44		$	67.50
Average wellhead differential percentage to NYMEX price		89	%		89	%		90	%
Hedging gain		—			—			5.11
Average realized price	$	59.03		$	56.44		$	72.61
Natural gas ($ per unit of measure):
Average NYMEX price ($/MMBtu)	$	7.22		$	6.87		$	7.75
Average differential to NYMEX (excluding hedge impacts)(1)		(0.14	)		0.26			(0.02	)
Average wellhead price ($/Mcf)	$	7.08		$	7.13		$	7.73
Average wellhead differential percentage to NYMEX price(1)		98	%		104	%		100	%
Hedging gain		—			—			0.25
Average realized price ($/Mcf)(1)	$	7.08		$	7.13		$	7.98
Total average combined wellhead price (Excluding hedge impacts) ($/Mcfe)	$	7.71		$	7.62		$	8.85

(1) Calculated differentials includes NGLs.

Our oil wellhead price as a percentage of the average NYMEX price is expected to average 90% for the twelve months ending December 31, 2008 as compared to 89% on a pro forma basis for the twelve months ended December 31, 2006 and June 30, 2007. Our natural gas wellhead price as a percentage of the average NYMEX price is expected to average 100% for the twelve months ending December 31, 2008 as compared to 98% and 104% on a pro forma basis for the twelve months ended December 31, 2006 and June 30, 2007, respectively.

As of October 25, 2007, Petrohawk has hedged and will assign to us upon the closing of this offering swaps covering 275 MBbls, or approximately 83%, of our total estimated oil production of 331 MBbls for the twelve months ending December 31, 2008, at a weighted average NYMEX oil price of $81.17 per Bbl. We have assumed an oil price of $75.00 per Bbl for the portion of our forecasted crude oil volumes that are unhedged (approximately 17%). As a result, we estimate that we will realize a weighted average oil sales price of $72.61 per Bbl for the 12 months ending December 31, 2008.

As of October 25, 2007, Petrohawk has hedged and will assign to us upon the closing of this offering swaps covering 3,660,000 MMBtu, or approximately 66%, of our total estimated natural gas production of 5,527 MMcf (excluding NGLs) for the twelve months ending December 31, 2008. We have utilized actual hedge prices with respect to volumes hedged as of October 25, 2007 at a weighted average NYMEX Henry Hub natural gas price of $8.25 per MMBtu. We have assumed a natural gas price of $7.75 per Mcf for the portion of our forecasted

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natural gas volumes that are unhedged (approximately 34%). As a result, we estimate that we will realize a weighted average natural gas sales price of $7.98 per MMBtu (including NGLs) for the twelve months ending December 31, 2008. At the closing of this offering, we intend to have hedged approximately 80% to 85% of our estimated net oil and natural gas production from proved developed producing reserves for a period of at least three years. The impact of these additional hedges is not reflected in our projected weighted average prices in the forecast periods.

The table below shows the volumes and prices of the derivative financial instruments for 2008 that were in place as of October 25, 2007 which Petrohawk will assign to us at the closing of this offering. For the 2008 calendar year, approximately 66% of our forecasted natural gas production (excluding NGLs) and 83% of our forecasted oil production are covered by derivatives.

	Swaps
	MMBtu	Weighted Average Price Per MMBtu
Natural Gas:
January 2008 —December 2008	3,660,000	$	8.25
January 2009 —December 2009	3,660,000	$	8.46
January 2010 —December 2010	3,660,000	$	8.25

	MBbls	Weighted Average Price Per Bbl
Oil:
January 2008 —December 2008	275	$	81.17
January 2009 —December 2009	275	$	77.00
January 2010 —December 2010	275	$	75.28

The following table summarizes our anticipated realized oil and natural gas prices on a pro forma basis for the twelve months ended December 31, 2006 and June 30, 2007 and on a forecasted basis for the twelve months ending December 31, 2008, as adjusted for average wellhead price differentials as well as actual hedges in place as described above:

	Pro Forma for the Twelve Months Ended				Forecasted for the Twelve Months Ending December 31, 2008
	December 31, 2006		June 30, 2007
Oil ($/Bbl):
Average wellhead price	$	59.03	$	56.44	$	67.50
Hedging gain(1)		—		—		5.11
Average realized price	$	59.03	$	56.44	$	72.61
Natural gas ($/Mcf):
Average wellhead price	$	7.08	$	7.13	$	7.73
Hedging gain(1)		—		—		0.25
Average realized price	$	7.08	$	7.13	$	7.98

(1) No derivative contracts have been allocated to these properties in our pro forma financial statements.

As reflected in the above table, we did not have any hedging arrangements on a pro forma basis for the twelve months ended December 31, 2006 or the twelve months ended June 30, 2007.

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Oil and Natural Gas Revenues. The following table illustrates the primary components of operating revenues on a pro forma basis for the twelve months ended December 31, 2006 and June 30, 2007 and on a forecasted basis for the twelve months ending December 31, 2008 (in thousands):

	Pro Forma for the Twelve Months Ended				Forecasted for the Twelve Months Ending December 31, 2008
	December 31, 2006		June 30, 2007
Oil:
Wellhead revenues	$	21,309	$	19,810	$	22,360
Hedging gain(1)		—		—		1,693
Total oil revenues	$	21,309	$	19,810	$	24,053
Natural gas:
Wellhead revenues	$	56,284	$	55,200	$	57,333
Hedging gain(1)		—		—		1,821
Total natural gas revenues(2)	$	56,284	$	55,200	$	59,154

(1) No derivative contracts have been allocated to these properties in our pro forma financial statements.

(2) Includes NGLs.

Capital Expenditures and Operating Expenses

Capital Expenditures. Our estimated cash reserves for maintenance capital expenditures for the year ending December 31, 2008 of $18.8 million represents our current estimate of the average annual maintenance capital expenditures necessary to maintain our production levels and asset base over the long-term. For the twelve months ending December 31, 2007, we estimate that our total capital expenditures will be approximately $14.0 million, which we anticipate will result in maintaining our production levels essentially flat throughout 2007 at approximately 26 MMcfe/d. We estimate that our actual capital expenditures for the twelve months ending December 31, 2008 will be approximately $16 million as compared to $32.8 million and $20.9 million on a pro forma basis for the twelve months ended December 31, 2006 and June 30, 2007, respectively. This anticipated decrease is the result of lower levels of budgeted development drilling in the forecast period.

We anticipate replacing our production and reserves through the drilling of wells on our properties and through the acquisition of producing and non-producing oil and natural gas properties from Petrohawk and from third parties. In our forecast for the twelve months ending December 31, 2008 we project estimated maintenance capital expenditures of $18.8 million. Of this amount, approximately $16 million represents identified development drilling and workover projects. We estimate that we will drill and complete 7 gross (6.9 net) operated wells and 40 gross (5.2 net) non-operated development wells during the forecast period at an aggregate cost of approximately $5.4 million and $4.0 million, respectively. The remaining $6.6 million of our forecasted capital expenditures for the twelve months ending December 31, 2008 is anticipated to consist of workover projects. Although the approximately $16 million to be spent in 2008 is expected to enable us to achieve our 2008 forecasted production rate, we expect that the remaining $2.8 million of estimated maintenance capital expenditures will be reserved for either acquisitions or increased drilling in future periods so that we can maintain our current production levels and asset base over the long term. Although we anticipate making acquisitions during the year ended December 31, 2008, our forecast period information does not reflect any acquisitions as we cannot be assured that we will be able to identify attractive properties or, if identified, that we will be able to acquire the properties.

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Lease Operating Expense and Other Operating Expenses. The following table summarizes lease operating expenses and other operating expenses on an aggregate basis and on a per Mcfe basis for the pro forma twelve months ended December 31, 2006 and June 30, 2007 and on a forecasted basis for the twelve months ending December 31, 2008 (in thousands, except per Mcfe amounts):

	Pro Forma for the Twelve Months Ended				Forecasted for the Twelve Months Ending December 31, 2008
	December 31, 2006		June 30, 2007
Lease operating expenses	$	10,328	$	10,572	$	10,721
Other operating expenses(1)		1,730		1,497		1,599
Total operating expenses	$	12,058	$	12,069	$	12,320
Lease operating expenses ($/Mcfe)	$	1.02	$	1.07	$	1.14
Other operating expenses ($/Mcfe)		0.17		0.15		0.17
Total operating expenses ($/Mcfe)	$	1.19	$	1.22	$	1.31

(1) Includes workover and gathering, transportation and other expenses.

We estimate that our lease operations expenses for the twelve months ending December 31, 2008 will be approximately $10.7 million as compared to $10.3 million and $10.6 million on a pro forma basis for the twelve months ended December 31, 2006 and June 30, 2007, respectively. The increase in forecasted lease operations expenses is primarily attributable to the following:

• expected increases in prices paid to oilfield service companies and suppliers due to a current higher price environment; and

• increased operational activity to maximize production and revenues.

Our other operating expenses consist primarily of gathering, transportation and processing expenses and workover expense associated with our oil and natural gas production. We estimate that our other operating expenses projected for the twelve months ending December 31, 2008 will be approximately $1.6 million as compared to $1.7 million and $1.5 million of pro forma other operating expenses for the twelve months ended December 31, 2006 and June 30, 2007, respectively.

Taxes Other Than Income. The following table summarizes production taxes on an aggregate pro forma basis and as a percentage of wellhead revenues for the twelve months ended December 31, 2006 and June 30, 2007 and for the twelve months ending December 31, 2008 (in thousands, except percentages):

	Pro Forma for the Twelve Months Ended						Forecasted for the Twelve Months Ending December 31, 2008
	December 31, 2006			June 30, 2007
Wellhead revenues	$	78,285		$	75,627		$	79,693
Taxes other than income		7,467			7,631			7,467
Production taxes as a percentage of wellhead revenues		9.5	%		10.1	%		9.4	%

Our production taxes are calculated as a percentage of our oil and natural gas revenues, excluding the effects of our derivative financial instruments. In general, as prices and volumes increase, our production taxes increase, and as prices and volumes decrease, our production taxes decrease. Additionally, production tax percentages vary by state and as revenues by state vary, it can cause increases or decreases in our overall rate.

General and Administrative Expenses.We estimate that our general and administrative expenses projected for the twelve months ending December 31, 2008 will remain at $5.7 million, which were our general and administrative expenses on a pro forma basis for the twelve months ended December 31, 2006 and June 30, 2007,

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respectively. Our forecasted and pro forma general and administrative expenses are comprised of allocated general and administrative costs from Petrohawk as well as $2.8 million ofincremental general and administrative expenses that we expect to incur as a result of being a public company. These expenses will include costs associated with annual and quarterly reports to unitholders, tax return and Schedule K-1 preparation and distribution, investor relations activities, registrar and transfer agent fees, incremental director and officer liability insurance costs and independent director compensation. At the closing of this offering, we expect to enter into an administrative services agreement with Petrohawk, HK Management and our general partner whereby Petrohawk will operate our assets and perform other administrative services for us and be reimbursed for its expenses incurred on our behalf. We have not included any non-cash unit based compensation expense in our forecast of general and administrative expenses.

Interest Expense. We estimate that our interest expense projected for the twelve months ending December 31, 2008 will be approximately $5.5 million as compared to $5.0 million on a pro forma basis for the twelve months ended December 31, 2006 and June 30, 2007. For the twelve months ending December 31, 2008, we expect to have an average of approximately $58.1 million in revolving debt outstanding and $165.0 million of term debt outstanding under our credit facility. Our term borrowings will be secured by $165.0 million in qualifying investment grade securities. Interest expense is calculated on the basis of an anticipated borrowing rate of 7.5% on our revolving debt and we expect that borrowings of term debt under our credit facility associated with our purchase of $165.0 million of qualifying investment grade securities, net of interest income earned on such securities, will bear an interest rate of 0.5%. This borrowing rate is applied against the average balance expected to be outstanding under our new revolving credit facility.

Regulatory, Industry and Economic Factors. Our forecast for the twelve months ending December 31, 2008 is based on the following significant assumptions related to regulatory, industry and economic factors:

• there will not be any new federal, state or local regulation of portions of the energy industry in which we operate, or an interpretation of existing regulation, that will be materially adverse to our business;

• there will not be any major adverse change in commodity prices or the energy industry in general; and

• market, insurance and overall economic conditions will not change substantially.

Distributions

Forecasted Distributions. We expect that the aggregate quarterly distributions paid to the holders of our common units, subordinated units and general partner interests for the twelve months ending December 31, 2008 are forecasted to be $29.1 million in the aggregate. Quarterly distributions will be paid within 45 days after the close of each quarter.

Sensitivity Analysis

Our ability to generate sufficient cash from our operations to pay distributions to our unitholders of not less than the minimum quarterly distribution per unit for the twelve months ending December 31, 2008 is a function of two primary variables: production volumes and commodity prices. In the paragraphs below, we discuss the impact that changes in either of these variables, while holding all other variables constant, would have on our ability to generate sufficient cash from our operations to pay the minimum quarterly distribution on all of our outstanding common units and subordinated units and the related distributions on our general partner’s 2% general partner interest for the year ending December 31, 2008.

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Production volume changes. The following table shows Adjusted EBITDA under various assumed production levels for the twelve months ending December 31, 2008. The Adjusted EBITDA amounts shown below are based on realized commodity prices that take into account our average NYMEX commodity price differential assumptions and effects of applicable derivative financial instruments currently in place.

Percentage of forecasted net production	95%			100%			105%
Oil (MBbl)		315			331			348
Natural gas (MMcf)		7,046			7,417			7,788
Total Production (MMcfe)		8,936			9,405			9,876
Average oil production (Bbl/d)		860			905			950
Average natural gas production (Mcf/d)		19,252			20,265			21,278
Total average production (MMcfe/d)		24.4			25.7			27.0
(In thousands)
Total revenues	$	75,709		$	79,693		$	83,678
Gain (loss) on derivative contracts		3,514			3,514			3,514
Operating expenses		(18,798	)		(19,787	)		(20,777	)
General and administrative expenses		(5,723	)		(5,723	)		(5,723	)
Adjusted EBITDA	$	54,702		$	57,697		$	60,692

Commodity price changes. The following table shows estimated Adjusted EBITDA sensitivities under various assumed NYMEX oil and natural gas prices for the twelve months ending December 31, 2008. The estimated Adjusted EBITDA amounts shown below are based on realized oil and natural gas prices that take into account our average NYMEX oil and natural gas price differential assumptions of 90% and 98% (100% with NGLs) of NYMEX, respectively, and applicable derivative financial instruments currently in place. We have assumed no changes in our production based on changes in prices and that our hedging counterparties will perform as expected (in thousands, except per unit, per day amounts and percentages).

Average NYMEX oil price ($/Bbl)	$	65.00		$	70.00		$	75.00		$	80.00		$	85.00
Average NYMEX natural gas price ($/MMBtu)	$	7.25		$	7.50		$	7.75		$	8.00		$	8.25
Total average production (MMcfe/d)		25.7			25.7			25.7			25.7			25.7
Percentage natural gas		79	%		79	%		79	%		79	%		79	%
Total revenues	$	71,956		$	75,825		$	79,693		$	83,562		$	87,430
Gain (loss) on derivative contracts		8,089			5,801			3,514			1,226			(1,061	)
Operating expenses		12,320			12,320			12,320			12,320			12,320
Production taxes		6,742			7,104			7,467			7,829			8,192
General and administrative expenses		5,723			5,723			5,723			5,723			5,723
Adjusted EBITDA	$	55,260		$	56,479		$	57,697		$	58,916		$	60,134

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HOW WE WILL MAKE CASH DISTRIBUTIONS

Set forth below is a summary of the significant provisions of our partnership agreement that relate to cash distributions.

Distributions of Available Cash

General. Our partnership agreement requires that, within 45 days after the end of each quarter, beginning with the quarter ending March 31, 2008, we distribute all of our available cash to unitholders of record on the applicable record date.

Definition of Available Cash. Available cash generally means all cash on hand and cash equivalents at the end of that quarter:

• less the amount of cash reserves established by the board of directors of HK Management to:

• provide for the proper conduct of our business (including amounts for maintenance and expansion capital expenditures, future debt service requirements and for our anticipated credit needs);

• comply with applicable law, any of our debt instruments or other agreements; and

• provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters;

• plus, if the board of directors of HK Management so determines, all or a portion of cash and cash equivalents on hand on the date of determination of available cash for the quarter including cash from working capital borrowings. Working capital borrowings are borrowings used solely for working capital purposes or to pay distributions to unitholders.

Intent to Distribute the Minimum Quarterly Distribution. We intend to distribute to the holders of common units and subordinated units on a quarterly basis at least the minimum quarterly distribution of $0.35 per unit, or $1.40 per unit on an annualized basis, to the extent we have sufficient cash from our operations after establishment of cash reserves and payment of fees and expenses, including payments to our general partner and its affiliates. However, there is no guarantee that we will pay the minimum quarterly distribution on the units in any quarter. Even if our cash distribution policy is not modified or revoked, the amount of distributions paid under our policy and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement. We will be prohibited from making any distributions to unitholders if it would cause an event of default, or an event of default exists, under our credit facility. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Capital Resources and Liquidity — Credit Facility” for a discussion of the restrictions to be included in our new credit facility that may restrict our ability to make distributions.

General Partner Interest. Initially, our general partner will own a 2% general partner interest and be entitled to 2% of all quarterly distributions that we make prior to our liquidation. Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its current general partner interest. The general partner’s initial 2% interest in these distributions will be reduced if we issue additional units in the future and our general partner does not contribute a proportionate amount of capital to us to maintain its 2% general partner interest.

Incentive Distribution Rights. Our general partner also will hold incentive distribution rights that entitle it to receive increasing percentages, up to a maximum of 25%, of the cash we distribute from operating surplus (as defined below) in excess of $0.35 per unit per quarter. The maximum distribution percentage of 25% includes distributions paid to our general partner on its initial 2% general partner interest and assumes that our general partner maintains its general partner interest at 2%. The maximum distribution percentage of 25% does not include any distributions that our general partner may receive on common and subordinated units that it owns. See “— Incentive Distribution Rights” for additional information.

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Operating Surplus and Capital Surplus

General. All cash we distribute to unitholders will be characterized as either “operating surplus” or “capital surplus.” Our partnership agreement requires that we distribute available cash from operating surplus differently than available cash from capital surplus.

Operating Surplus. Operating surplus generally means:

• $                    ; plus

• all of our cash receipts after the closing of this offering, excluding cash from interim capital transactions; plus

• working capital borrowings made after the end of a quarter but before the date of determination of operating surplus for the quarter; less

• our operating expenditures after the closing of this offering; less

• the amount of cash reserves established by our general partner to provide funds for future operating and capital expenditures; less

• all working capital borrowings not repaid within twelve months after having been incurred.

If working capital borrowings are not repaid during the twelve-month period following the borrowing, they will be deemed repaid at the end of such period, thus decreasing operating surplus at such time. When such working capital borrowings are in fact repaid, they will not be treated as a reduction in operating surplus because operating surplus will have been previously reduced by the deemed repayment. Because of fluctuations in our working capital, we may make short-term working capital borrowings in order to level out our distributions from quarter to quarter.

Part of our business strategy is to limit our exposure to volatility in commodity prices by entering into hedging agreements. In general, all of the payments we make or receive under hedging agreements, including periodic settlement payments, the purchase price of put contracts and payments made or received in connection with the termination of hedging agreements, will be added or deducted in the determination of operating surplus on the date the payment is received or made. Our partnership agreement allows our general partner, with the approval of the conflicts committee of HK Management’s board of directors, to allocate payments made or received under hedging agreements over multiple periods, or to exclude such payments or receipts from the calculation of operating surplus if it determines such treatment to be appropriate.

Interim Capital Transactions. Amounts we receive from interim capital transactions are not added to the amount we receive from operating sources in calculating operating surplus. Interim capital transactions generally means the following:

• borrowings (other than working capital borrowings);

• sales of our equity and debt securities;

• the termination of interest rate and commodity swap agreements; and

• sales or other dispositions of assets for cash, other than sales of oil and natural gas production, disposition of assets made in connection with plugging and abandoning wells and site reclamation, sales of inventory, accounts receivable and other current assets sold in the ordinary course of business or as part of normal retirement or replacement of assets.

Working capital borrowings are short-term borrowings that we make in order to finance our operations or pay distributions to our partners. Working capital borrowings increase operating surplus and repayment of these borrowings decreases operating surplus.

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If a working capital borrowing is not repaid during the twelve-month period following the borrowing, it will be deemed repaid at the end of such period, thus decreasing operating surplus at such time. When such working capital borrowing is in fact repaid, it will not be treated as a reduction in operating surplus because operating surplus will have been previously reduced by the deemed repayment.

Because of fluctuations in our working capital, we may make short term working capital borrowings in order to balance out our distributions from quarter to quarter.

Operating Expenditures. Operating expenditures generally means all of our expenditures, including lease and well operating expenses, taxes, reimbursements of expenses to our general partner, payments made in the ordinary course of business under interest rate and commodity hedge contracts, estimated maintenance capital expenditures, repayment of working capital borrowings and debt service payments. Operating expenditures will not include:

• actual repayment of working capital borrowings deducted from operating surplus that were deemed to have been repaid at the end of the twelve-month period following the borrowing;

• payments (including prepayments and prepayment penalties) of principal of and premium on indebtedness, other than working capital borrowings;

• actual maintenance capital expenditures;

• expansion capital expenditures;

• investment capital expenditures;

• payment of transaction expenses relating to interim capital transactions; or

• distributions to partners.

Maintenance Capital Expenditures. For purposes of determining operating surplus, maintenance capital expenditures are those capital expenditures required to maintain our current production levels and asset base over the long-term or maintain the current operating capacity of our other capital assets. Examples of maintenance capital expenditures include capital expenditures to bring our non-producing reserves into production, such as drilling and completion costs, enhanced recovery costs and other construction costs, and costs to acquire reserves that replace the reserves we expect to produce in the future. Maintenance capital expenditures will also include interest (and related fees) on debt incurred and distributions on equity issued to finance all or any portion of a replacement asset during the period from such financing until the earlier to occur of the date any such replacement asset is placed into service or the date that it is abandoned or disposed of. Well plugging and abandonment, site restoration and similar costs will also constitute maintenance capital expenditures.

Estimated Average Maintenance Capital Expenditures. Our general partner will be required to estimate the average maintenance capital expenditures we will make over the long-term, and deduct that estimate in calculating operating surplus. Because our maintenance capital expenditures can be very large and irregular, the amount of our actual maintenance capital expenditures may differ substantially from period to period, which could cause similar fluctuations in the amounts of operating surplus and adjusted operating surplus (as described below) if we subtracted our actual maintenance capital expenditures when we calculate operating surplus. Accordingly, to eliminate the effect of these fluctuations on operating surplus, our partnership agreement will require that an estimate of the average quarterly maintenance capital expenditures expected to be necessary to maintain our current production levels and asset base over the long-term or maintain the current operating capacity of our other capital assets over the long term be subtracted in calculating operating surplus each quarter as opposed to the actual amounts we spend. The amount of estimated average maintenance capital expenditures deducted from operating surplus is subject to review and change by the board of directors of HK Management at least once a year, provided that any change is approved by HK Management’s conflicts committee. The estimate will be made at least annually and whenever an event occurs that is likely to result in a material adjustment to the amount of our maintenance

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capital expenditures, such as a major acquisition or the introduction of new governmental regulations that will impact our business. For purposes of calculating operating surplus, any adjustment to this estimate will be prospective only.

The use of estimated average maintenance capital expenditures in calculating operating surplus will have the following effects:

• it will reduce the risk that maintenance capital expenditures in any one quarter will be large enough to render our operating surplus less than the minimum quarterly distribution to be paid on all the units and the related distribution on our general partner’s 2% general partner interest for that quarter and subsequent quarters;

• it will reduce the need to borrow under our credit facility to pay distributions;

• it will be more difficult for us to raise our distribution above the minimum quarterly distribution and pay incentive distributions to our general partner; and

• it will reduce the likelihood that a large maintenance capital expenditure in a period will prevent the conversion of some or all of their subordinated units into common units since the effect of an estimate is to spread the expected expense over several periods, thereby mitigating the effect of the actual payment of the expenditure on any single period.

Expansion Capital Expenditures. Expansion capital expenditures are those capital expenditures that we expect will increase our current production levels and asset base over the long-term or increase the current operating capacity of our other capital assets over the long-term. Examples of expansion capital expenditures include the acquisition of oil and natural gas properties or equipment or new exploration or development prospects, to the extent we expect that such expenditures will increase our current production levels and asset base over the long-term. Expansion capital expenditures will also include interest (and related fees) on debt incurred and distributions on equity issued to finance all or any portion of such capital improvement during the period from such financing until the earlier to occur of the date any such capital improvement is placed into service or the date that it is disposed of or abandoned. Capital expenditures made solely for investment purposes will not be considered expansion capital expenditures.

Miscellaneous. Amounts that we invest in certificates of deposit or securities or other temporary investments pending use in our business will not be deducted in calculating operating surplus.

As described above, operating surplus does not reflect actual cash on hand that is available for distribution to our unitholders. For example, it includes a provision that will enable us, if we choose, to distribute as operating surplus up to two times the amount needed for any one quarter to pay a distribution on all of our units that we receive in the future from non-operating sources such as asset sales, issuances of securities and long-term borrowings that would otherwise be distributed as capital surplus. As a result, we may also distribute as operating surplus up to the amount of any such cash distribution or interest payments of cash we receive from non-operating sources.

Definition of Capital Surplus. Capital surplus will generally be generated only by:

• borrowings other than working capital borrowings;

• sales of debt and equity securities; and

• sales or other dispositions of assets for cash, other than sales of natural gas and oil production, dispositions of assets made in connection with plugging and abandoning wells and site reclamation, sales of inventory, accounts receivable and other current assets sold in the ordinary course of business or as part of normal retirements or replacements of assets.

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Characterization of Cash Distributions. Our partnership agreement requires that we treat all available cash distributed as coming from operating surplus until the sum of all available cash distributed since the closing of this offering equals the operating surplus as of the most recent date of determination of available cash. Our partnership agreement requires that we treat any amount distributed in excess of operating surplus, regardless of its source, as capital surplus. We do not anticipate that we will make any distributions from capital surplus.

Subordination Period

General. Our partnership agreement provides that, during the subordination period (which we define below and in Appendix A), the common units will have the right to receive distributions of available cash from operating surplus each quarter in an amount equal to $0.35 per common unit, which amount is defined in our partnership agreement as the minimum quarterly distribution, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, and the general partner has received its 2% distribution, before any distributions of available cash from operating surplus may be made on the subordinated units. These units are deemed “subordinated” because for a period of time, referred to as the subordination period, the subordinated units will not be entitled to receive any distributions until the common units have received the minimum quarterly distribution plus any arrearages from prior quarters and the general partner has received its 2% distribution. Furthermore, no arrearages will be paid on the subordinated units. The practical effect of the subordinated units is to increase the likelihood that during the subordination period there will be available cash to be distributed on the common units.

Subordination Period. The subordination period will extend until the first day of any quarter beginning after December 31, 2010 that each of the following tests are met:

• distributions of available cash from operating surplus on each of the outstanding common units, subordinated units and the 2% general partner interest equaled or exceeded the minimum quarterly distribution for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date;

• the “adjusted operating surplus” (as defined below) generated during each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum of the minimum quarterly distributions on all of the outstanding common and subordinated units and the 2% general partner interest during those periods on a fully diluted basis; and

• there are no arrearages in payment of the minimum quarterly distribution on the common units.

Expiration of the Subordination Period. When the subordination period expires, each outstanding subordinated unit will convert into one common unit and will then participate pro rata with the other common units in distributions of available cash. In addition, if the unitholders remove our general partner other than for cause and units held by the general partner and its affiliates are not voted in favor of such removal:

• the subordination period will end and each subordinated unit will immediately convert into one common unit;

• any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and

• the general partner will have the right to convert its 2% general partner interest and its incentive distribution rights into common units or to receive cash in exchange for those interests.

Adjusted Operating Surplus. Adjusted operating surplus for any period generally consists of:

• operating surplus generated with respect to that period; less

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• any net increase in working capital borrowings with respect to that period; less

• any net reduction in cash reserves for operating expenditures with respect to that period not relating to an operating expenditure made with respect to that period; plus

• any net decrease in working capital borrowings with respect to that period; plus

• any net increase in cash reserves for operating expenditures made with respect to that period required by any debt instrument for the repayment of principal, interest or premium.

Adjusted operating surplus is intended to reflect the cash generated from operations during a particular period and therefore excludes cash on hand at the closing of this offering, net increases in working capital borrowings and net drawdowns of reserves of cash generated in prior periods. Adjusted operating surplus is calculated using estimated maintenance capital expenditures, rather than actual maintenance capital expenditures and, to the extent the estimated amount for a period is less than the actual amount, the cash generated from operations during that period would be less than adjusted operating surplus.

Distributions of Available Cash from Operating Surplus during the Subordination Period

Our partnership agreement requires that we make distributions of available cash from operating surplus for any quarter during the subordination period in the following manner:

• first, 98% to the common unitholders, pro rata, and 2% to the general partner, until we distribute for each outstanding common unit an amount equal to the minimum quarterly distribution for that quarter;

• second, 98% to the common unitholders, pro rata, and 2% to the general partner, until we distribute for each outstanding common unit an amount equal to any arrearages in payment of the minimum quarterly distribution on the common units for any prior quarters during the subordination period;

• third, 98% to the subordinated unitholders, pro rata, and 2% to the general partner, until we distribute for each subordinated unit an amount equal to the minimum quarterly distribution for that quarter; and

• thereafter, in the manner described in “— Incentive Distribution Rights” below.

The preceding discussion is based on the assumptions that our general partner maintains its 2% general partner interest and that we do not issue additional classes of equity securities.

Distributions of Available Cash from Operating Surplus after the Subordination Period

• Our partnership agreement requires that we make distributions of available cash from operating surplus for any quarter after the subordination period in the following manner:

• first, 98% to all unitholders, pro rata, and 2% to the general partner, until we distribute for each outstanding unit an amount equal to the minimum quarterly distribution for that quarter; and

• thereafter, in the manner described in “— Incentive Distribution Rights” below.

The preceding discussion is based on the assumptions that our general partner maintains its 2% general partner interest and that we do not issue additional classes of equity securities.

Incentive Distribution Rights

Incentive distribution rights represent the right to receive an increasing percentage (13% and 23%) of quarterly distributions of available cash from operating surplus after the minimum quarterly distribution and the

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target distribution levels have been achieved. Our general partner currently holds the incentive distribution rights, but may transfer these rights separately from its general partner interest, subject to restrictions in our partnership agreement.

If for any quarter:

• we have distributed available cash from operating surplus to the common and subordinated unitholders in an amount equal to the minimum quarterly distribution; and

• we have distributed available cash from operating surplus on outstanding common units in an amount necessary to eliminate any cumulative arrearages in payment of the minimum quarterly distribution;

then, our partnership agreement requires that we distribute any additional available cash from operating surplus for that quarter among the unitholders and the general partner in the following manner:

• first, 98% to all unitholders, pro rata, and 2% to the general partner, until each unitholder receives a total of $0.4025 per unit for that quarter (the “first target distribution”);

• second, 85% to all unitholders, pro rata, and 15% to the general partner, until each unitholder receives a total of $0.4375 per unit for that quarter (the “second target distribution”); and

• thereafter, 75% to all unitholders, pro rata, and 25% to the general partner.

The preceding discussion is based on the assumptions that our general partner maintains its 2% general partner interest and that we do not issue additional classes of equity securities.

General Partner’s Right to Reset Target Distribution Levels

Our general partner, as the holder of our incentive distribution rights, has the right under our partnership agreement to elect to relinquish the right to receive incentive distribution payments based on the initial cash target distribution levels and to reset, at higher levels, the minimum quarterly distribution amount and cash target distribution levels upon which the incentive distribution payments to our general partner would be set. Our general partner’s right to reset the minimum quarterly distribution amount and the target distribution levels upon which the incentive distributions payable to our general partner are based may be exercised, without approval of our unitholders or the conflicts committee of HK Management, at any time when there are no subordinated units outstanding and we have made cash distributions to the holders of the incentive distribution rights at the highest level of incentive distribution for each of the prior four consecutive fiscal quarters. The reset minimum quarterly distribution amount and target distribution levels will be higher than the minimum quarterly distribution amount and the target distribution levels prior to the reset such that our general partner will not receive any incentive distributions under the reset target distribution levels until cash distributions per unit following this event increase as described below. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would otherwise not be sufficiently accretive to cash distributions per common unit, taking into account the existing levels of incentive distribution payments being made to our general partner.

In connection with the resetting of the minimum quarterly distribution amount and the target distribution levels and the corresponding relinquishment by our general partner of incentive distribution payments based on the target cash distributions prior to the reset, our general partner will be entitled to receive a number of newly issued Class B units based on a predetermined formula described below that takes into account the “cash parity” value of the average cash distributions related to the incentive distribution rights received by our general partner for the two consecutive fiscal quarters immediately prior to the reset event as compared to the average cash distributions per common unit during this period.

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The number of Class B units that our general partner would be entitled to receive from us in connection with a resetting of the minimum quarterly distribution amount and the target distribution levels then in effect would be equal to (x) the average amount of cash distributions received by our general partner in respect of its incentive distribution rights during the two consecutive fiscal quarters ended immediately prior to the date of such reset election divided by (y) the average of the amount of cash distributed per common unit during each of these two quarters. Each Class B unit will be convertible into one common unit at the election of the holder of the Class B unit at any time following the first anniversary of the issuance of these Class B units.

Following a reset election by our general partner, the minimum quarterly distribution amount will be reset to an amount equal to the average cash distribution amount per common unit for the two consecutive fiscal quarters immediately preceding the reset election (such amount is referred to as the “reset minimum quarterly distribution”) and the target distribution levels will be reset to be correspondingly higher such that we would distribute all of our available cash from operating surplus for each quarter thereafter as follows:

• first, 98% to all unitholders, pro rata, and 2% to the general partner, until each unitholder receives an amount equal to 115% of the reset minimum quarterly distribution for that quarter;

• second, 85% to all unitholders, pro rata, and 15% to the general partner, until each unitholder receives an amount per unit equal to 125% of the reset minimum quarterly distribution for that quarter; and

• thereafter, 75% to all unitholders, pro rata, and 25% to the general partner.

The following table illustrates the percentage allocation of available cash from operating surplus between the unitholders and our general partner at various levels of cash distribution levels pursuant to the cash distribution provision of our partnership agreement in effect at the closing of this offering as well as following a hypothetical reset of the minimum quarterly distribution and target distribution levels based on the assumption that the average quarterly cash distribution amount per common unit during the two fiscal quarters immediately preceding the reset election was $0.5250. The amounts set forth under “Marginal Percentage Interest in Distributions” are the percentage interests of our unitholders and our general partner in any available cash from operating surplus we distribute up to and including the corresponding amount in the column “Total Quarterly Distribution Target Amount Per Unit,” until available cash from operating surplus we distribute reaches the next target distribution level, if any. The percentage interests shown for the unitholders and our general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution.

		Marginal Percentage Interest in Distributions
	Total Quarterly Distribution Target Amount Per Unit	Unitholders		General Partner		Holders of Incentive Distribution Rights
Minimum Quarterly Distribution	$0.3500	98	%	2	%	—
First Target Distribution	above $0.3500 up to $0.4025	98	%	2	%	—
Second Target Distribution	above $0.4025 up to $0.4375	85	%	2	%	13	%
Thereafter	above $0.4375	75	%	2	%	23	%

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The following table illustrates the total amount of available cash from operating surplus that would be distributed to the unitholders and the general partner, including in respect of incentive distribution rights, or IDRs, based on an average of the amounts distributed for a quarter for the two quarters immediately prior to the reset. The table assumes that there are 20,343,790 common units outstanding, that our general partner has a 2% interest as a general partner, and that the average distribution to each common unit is $0.5250 for the two quarters prior to the reset.

	Quarterly Distribution per Unit Prior to Reset	Common Unitholders Cash Distribution Prior to Reset		General Partner Cash Distributions Prior to Reset								Total Distributions
				Class B Units		2% General Partner Interest		IDRs		Total
Minimum Quarterly Distribution	$0.3500	$	7,120,327	$	—	$	145,313	$	—	$	145,313	$	7,265,640
First Target Distribution	up to $0.4025		1,068,049		—		21,797		—		21,797		1,089,846
Second Target Distribution	above $0.4025		712,033		—		16,754		108,899		125,653		837,686
	up to $0.4375
Thereafter	above $0.4375		1,780,082		—		47,469		545,892		593,360		2,373,442
		$	10,680,491	$	—	$	231,333	$	654,791	$	886,123	$	11,566,614

The following table illustrates the total amount of available cash from operating surplus that would be distributed to the unitholders and the general partner with respect to the quarter in which the reset occurs. The table reflects that as a result of the reset there are 20,343,790 common units, 1,247,221 Class B units outstanding, that our general partner maintains its 2% general partner interest and that the average distribution to each common unit is $0.5250. The number of Class B units was calculated by dividing (x) the $654,791 received by the general partner in respect of its incentive distribution rights, or IDRs, as the average of the amounts received by the general partner in respect of its incentive distribution rights for the two quarters prior to the reset as shown in the table above by (y) the $0.5250 of available cash from operating surplus distributed to each common unit as the average distributed per common unit for the two quarters prior to the reset.

	Quarterly Distribution per Unit After Reset	Common Unitholders Cash Distribution After Reset		General Partner Cash Distributions After Reset								Total Distributions
				Class B Units		2% General Partner Interest		IDRs		Total
Minimum Quarterly Distribution	$0.5250	$	10,680,491	$	654,791	$	231,333	$	—	$	886,123	$	11,566,614
First Target Distribution	up to $0.6038		—		—		—		—		—		—
Second Target Distribution	above $0.6038
	up to $0.6563		—		—		—		—		—		—
Thereafter	above $0.6563		—		—		—		—		—		—
		$	10,680,491	$	654,791	$	231,333	$	—	$	886,123	$	11,566,614

Our general partner will be entitled to cause the minimum quarterly distribution amount and the target distribution levels to be reset on more than one occasion, provided that it may not make a reset election except at a time when it has received incentive distributions for the prior four consecutive fiscal quarters based on the highest level of incentive distributions that it is entitled to receive under our partnership agreement.

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Percentage Allocations of Available Cash from Operating Surplus

The following table illustrates the percentage allocations of available cash from operating surplus between the unitholders and our general partner based on the specified target distribution levels. The amounts set forth under “Marginal Percentage Interest in Distributions” are the percentage interests of our general partner and the unitholders in any available cash from operating surplus we distribute up to and including the corresponding amount in the column “Total Quarterly Distribution Per Unit,” until available cash from operating surplus we distribute reaches the next target distribution level, if any. The percentage interests shown for the unitholders and the general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. The percentage interests set forth below for our general partner include its 2% general partner interest and assume our general partner has contributed any additional capital to maintain its 2% general partner interest and has not transferred its incentive distribution rights.

	Total Quarterly Distribution per Unit	Marginal Percentage Interest in Distributions
	Target Amount	Unitholders		General Partner
Minimum Quarterly Distribution	$0.3500	98	%	2	%
First Target Distribution	up to $0.4025	98	%	2	%
Second Target Distribution	above $0.4025 up to $0.4375	85	%	15	%
Thereafter	above $0.4375	75	%	25	%

Distributions from Capital Surplus

How Distributions from Capital Surplus Will Be Made. Our partnership agreement requires that we make distributions of available cash from capital surplus, if any, in the following manner:

• first, 98% to all unitholders, pro rata, and 2% to the general partner, until we distribute for each common unit that was issued in this offering, an amount of available cash from capital surplus equal to the initial public offering price;

• second, 98% to the common unitholders, pro rata, and 2% to the general partner, until we distribute for each common unit, an amount of available cash from capital surplus equal to any unpaid arrearages in payment of the minimum quarterly distribution on the common units; and

• thereafter, we will make all distributions of available cash from capital surplus as if they were from operating surplus.

The preceding discussion is based on the assumption that our general partner maintains its 2% general partner interest and that we do not issue additional classes of equity securities.

Effect of a Distribution from Capital Surplus. Our partnership agreement treats a distribution of capital surplus as the repayment of the initial unit price from this initial public offering, which is a return of capital. The initial public offering price less any distributions of capital surplus per unit is referred to as the “unrecovered initial unit price.” Each time a distribution of capital surplus is made, the minimum quarterly distribution and the target distribution levels will be reduced in the same proportion as the corresponding reduction in the unrecovered initial unit price. Because distributions of capital surplus will reduce the minimum quarterly distribution, after any of these distributions are made, it may be easier for the general partner to receive incentive distributions and for the subordinated units to convert into common units. Any distribution of capital surplus before the unrecovered initial unit price is reduced to zero cannot be applied to the payment of the minimum quarterly distribution or any arrearages.

Once we distribute capital surplus on a unit issued in this offering in an amount equal to the initial unit price, our partnership agreement specifies that the minimum quarterly distribution and the target distribution

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levels will be reduced to zero. Our partnership agreement specifies that we then make all future distributions from operating surplus, with 75% being paid to the holders of units and 25% to the general partner. The percentage interests shown for our general partner include its 2% general partner interest and assume the general partner has not transferred the incentive distribution rights and that we do not issue additional classes of equity securities.

Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels

In addition to adjusting the minimum quarterly distribution and target distribution levels to reflect a distribution of capital surplus, if we combine our units into fewer units or subdivide our units into a greater number of units, our partnership agreement specifies that the following items will be proportionately adjusted:

• the minimum quarterly distribution;

• target distribution levels;

• the unrecovered initial unit price;

• the number of common units issuable during the subordination period without a unitholder vote; and

• the number of common units into which a subordinated unit is convertible.

For example, if a two-for-one split of the common units should occur, the minimum quarterly distribution, the target distribution levels and the unrecovered initial unit price would each be reduced to 50% of its initial level, the number of common units issuable during the subordination period without unitholder vote would double and each subordinated unit would be convertible into two common units. Our partnership agreement provides that we not make any adjustment by reason of the issuance of additional units for cash or property.

In addition, if legislation is enacted or if existing law is modified or interpreted by a court of competent jurisdiction or a governmental taxing authority, so that we become taxable as a corporation or otherwise subject to a material amount of entity-level taxation for federal, state or local income tax purposes, our partnership agreement specifies that the minimum quarterly distribution and the target distribution levels for each quarter will be reduced by multiplying each distribution level by a fraction, the numerator of which is available cash for that quarter (after deducting our general partner’s estimate of our aggregate liability for the quarter for such income taxes payable by reason of such legislation or interpretation) and the denominator of which is the sum of available cash for that quarter plus the general partner’s estimate of our aggregate liability for the quarter for such income taxes payable by reason of such legislation or interpretation. To the extent that the actual tax liability differs from the estimated tax liability for any quarter, the difference will be accounted for in subsequent quarters.

Distributions of Cash Upon Liquidation

General. If we dissolve in accordance with our partnership agreement, we will sell or otherwise dispose of our assets in a process called liquidation. We will first apply the proceeds of liquidation to the payment of our creditors. We will distribute any remaining proceeds to the unitholders and the general partner, in accordance with their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of our assets in liquidation.

The allocations of gain and loss upon liquidation are intended, to the extent possible, to entitle the holders of outstanding common units to a preference over the holders of outstanding subordinated units upon our liquidation, to the extent required to permit common unitholders to receive their unrecovered initial unit price plus the minimum quarterly distribution for the quarter during which liquidation occurs plus any unpaid arrearages in payment of the minimum quarterly distribution on the common units. There may not, however, be sufficient gain upon our liquidation to enable the holders of common units to fully recover all of these amounts,

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even though there may be cash available for distribution to the holders of subordinated units. Any further net gain recognized upon liquidation will be allocated in a manner that takes into account the incentive distribution rights of the general partner.

Maintenance of Capital Accounts. We will maintain capital accounts for each of our partners in accordance with the Treasury Regulation Sections under Section 704 of the Internal Revenue Code. A common unitholder’s initial capital account will be credited with the amount he paid for his common units, and the general partner’s initial capital account will be credited with the fair market value of the property contributed by the general partner in exchange for the general partner’s interests in us. Thereafter, the Treasury Regulations provide that a partner’s capital account must be increased by (i) any additional amount of money (or fair market value of property) that such partner has contributed to the partnership and (ii) such partner’s distributive share of partnership income and gain, including simulated gain and income and gain that is exempt from tax, and decreased by (x) the amount of money (or fair market value of property) distributed to such partner by the partnership, (y) such partner’s distributive share of certain partnership expenditures that are neither deductible nor properly capitalized and (z) such partners’ distributive share of partnership loss and deduction, including simulated loss and simulated depletion.

Manner of Adjustments for Gain. The manner of the adjustment for gain is set forth in our partnership agreement. If our liquidation occurs before the end of the subordination period, we will allocate any gain to the partners in the following manner:

• first, to our general partner and the holders of units who have negative balances in their capital accounts to the extent of and in proportion to those negative balances;

• second, 98% to the common unitholders, pro rata, and 2% to our general partner, until the capital account for each common unit is equal to the sum of: (1) the unrecovered initial unit price; (2) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs; and (3) any unpaid arrearages in payment of the minimum quarterly distribution;

• third, 98% to the subordinated unitholders, pro rata, and 2% to our general partner until the capital account for each subordinated unit is equal to the sum of: (1) the unrecovered initial unit price; and (2) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs

• fourth, 98% to all unitholders, pro rata, and 2% to our general partner, until we allocate under this paragraph an amount per unit equal to: (1) the sum of the excess of the first target distribution per unit over the minimum quarterly distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the minimum quarterly distribution per unit that we distributed 98% to the unitholders, pro rata, and 2% to our general partner, for each quarter of our existence;

• fifth, 85% to all unitholders, pro rata, and 15% to our general partner, until we allocate under this paragraph an amount per unit equal to: (1) the sum of the excess of the second target distribution per unit over the first target distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the first target distribution per unit that we distributed 85% to the unitholders, pro rata, and 15% to our general partner for each quarter of our existence; and

• thereafter, 75% to all unitholders, pro rata, and 25% to our general partner.

The percentage interests set forth above for our general partner assume that our general partner maintains its 2% general partner interest, that our general partner has not transferred the incentive distribution rights and that we did not issue additional classes of equity securities.

If the aggregate amount of a partner’s distributions and his allocable share of losses, including simulated loss and simulated depletion, exceed such partner’s aggregate capital contributions and his distributive share of

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income and gain, including simulated gain and income and gain that is exempt from tax, his capital account balance could be less than zero. Nonetheless, our partnership agreement includes specific allocations intended to prevent a limited partner from having a negative capital account. Only our general partner has an obligation to restore a negative capital account upon the liquidation of the partnership.

If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that clause (3) of the second bullet point above and all of the third bullet point above will no longer be applicable.

Manner of Adjustments for Losses. If our liquidation occurs before the end of the subordination period, we will generally allocate any loss to our general partner and the unitholders in the following manner:

• first, 98% to holders of subordinated units in proportion to the positive balances in their capital accounts and 2% to our general partner, until the capital accounts of the subordinated unitholders have been reduced to zero;

• second, 98% to the holders of common units in proportion to the positive balances in their capital accounts and 2% to our general partner, until the capital accounts of the common unitholders have been reduced to zero; and

• thereafter, 100% to our general partner.

If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that all of the first bullet point above will no longer be applicable.

Adjustments to Capital Accounts. Our partnership agreement requires that we make adjustments to capital accounts upon the issuance of additional units. In this regard, our partnership agreement specifies that we allocate any unrealized and, for tax purposes, unrecognized gain or loss resulting from the adjustments to the unitholders and our general partner in the same manner as we allocate gain or loss upon liquidation. In the event that we make positive adjustments to the capital accounts upon the issuance of additional units, our partnership agreement requires that we allocate any later negative adjustments to the capital accounts resulting from the issuance of additional units or upon our liquidation in a manner which results, to the extent possible, in our general partner’s capital account balances equaling the amount they would have been if no earlier positive adjustments to the capital accounts had been made.

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SELECTED HISTORICAL AND PRO FORMA FINANCIAL AND OPERATING DATA

The following tables present selected historical financial data for HK Energy Partners LP Predecessor, the predecessor to HK Energy Partners LP, and pro forma financial data of HK Energy Partners LP, as of the dates and for the periods indicated.

The statement of operations data for our predecessor for the years ended December 31, 2004, 2005 and 2006 and the balance sheet data as of December 31, 2005 and 2006 set forth below are derived from our audited carve out financial statements and the notes thereto included elsewhere in this document. The statement of operations data for our predecessor for the six months ended June 30, 2007 and 2006 and the balance sheet data as of June 30, 2007 are derived from our unaudited carve out financial statements included elsewhere in this document and, in the opinion of management, include all adjustments (consisting only of normal recurring accruals) necessary for a fair presentation of the financial position and results of operations as of the dates and for the periods indicated. The discussion of the results of operations for fiscal 2005 is based on the combined results for the period from January 1, 2005 through December 31, 2005.

The carve out financial statements of our predecessor are comprised of oil and natural gas assets, liabilities and operations located in the Permian Basin of West Texas and New Mexico currently owned by Petrohawk, which we refer to as the partnership properties, and which we will acquire upon the completion of this offering. The first table below does not include selected statement of operations data for our predecessor for the years ended December 31, 2003 and 2002. A combination of factors results in our inability to provide the 2003 and 2002 selected statement of operations information without unreasonable effort and expense. These factors are: (1) the predecessor was not accounted for as a separate entity, subsidiary or division of the business of Mission Resources Corporation, or Mission, and as a result, a statement of operations of the predecessor for 2003 and 2002 was not prepared and does not exist, (2) Petrohawk converted the historical accounting system during 2005 and information in the predecessor’s prior accounting system is not able to be reasonably accessed and utilized, and (3) Petrohawk has experienced a significant amount of Mission employee turnover and the time and costs associated with preparing a 2003 and 2002 statement of operations for the predecessor would be excessive and unreasonable. We believe that the omission of the selected statement of operations data for 2003 and 2002 would not have a material impact on a reader’s understanding of our financial results and related trends. Due to the factors described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Factors Affecting Comparability of Future Results,” our future results of operations may not be comparable to HK Energy Partners LP Predecessor’s historical results. The results for periods of less than a full year are not necessarily indicative of the results to be expected for any interim period or for a full year.

The selected pro forma statement of operations data presented for the year ended December 31, 2006 and as of and for the six months ended June 30, 2007 for HK Energy Partners LP gives pro forma effect to the following as if all transactions had been completed on January 1, 2006:

• the acquisition by Petrohawk of KCS Energy, Inc. on July 12, 2006;

• our entrance into the contribution agreement, pursuant to which:

• our general partner and another subsidiary of Petrohawk will contribute all of the partnership properties to us;

• we will issue 5,904,048 common units and 5,189,742 subordinated units to wholly owned subsidiaries of Petrohawk, representing an aggregate 53.4% limited partner interest in us as partial consideration for such contribution;

• we will sell 9,250,000 common units to the public in this offering, representing a 44.6% limited partner interest in us, and will use the proceeds as described in “Use of Proceeds”; and

• we will issue to HK Energy Partners GP LP a 2% general partner interest in us and all of our incentive distribution rights, which will entitle our general partner to increasing percentages of the cash we distribute in excess of $0.4025 per unit per quarter (115% of the minimum quarterly distribution);

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• expected borrowings of $165.0 million in term debt under our credit facility, which will be secured by $165.0 million of qualifying investment grade securities, and distribution of the funds to our general partner and another subsidiary of Petrohawk as partial consideration for the partnership properties contributed to us;

• expected borrowings of $58.1 million in revolving debt under our credit facility and distribution of the funds to our general partner and another subsidiary of Petrohawk as partial consideration for the partnership properties contributed to us;

• the entrance by us into an administrative services agreement with Petrohawk, HK Management and our general partner pursuant to which we will reimburse Petrohawk and its affiliates $5.7 million in allocated general and administrative costs, including $2.8 million in incremental costs related to being a publicly traded partnership.

The unaudited pro forma balance sheet assumes the transactions listed above occurred on June 30, 2007. The selected pro forma financial data is derived from pro forma financial statements of HK Energy Partners LP included elsewhere in this prospectus.

You should read the following table in conjunction with “Prospectus Summary — Formation Transactions and Partnership Structure,” “Use of Proceeds,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” the historical carve out financial statements of HK Energy Partners LP Predecessor, and the unaudited pro forma financial statements of HK Energy Partners LP included elsewhere in this prospectus. Among other things, those historical and pro forma financial statements include more detailed information regarding the basis of presentation for the following information.

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The following tables present a non-GAAP financial measure, Adjusted EBITDA, which we use in our business. This measure is not calculated or presented in accordance with accounting principles generally accepted in the United States of America, or GAAP. We explain this measure below and reconcile it to the most directly comparable financial measures calculated and presented in accordance with GAAP. The acquisition of certain oil and gas properties from KCS affects the comparability between the financial data below.

	Predecessor						Successor
(In thousands)	Year Ended December 31, 2004			Period From January 1, 2005 to July 27, 2005(1)			Period From July 28, 2005 to December 31, 2005(1)			Fiscal 2005 Combined(1)			Year Ended December 31, 2006			Six Months Ended June 30,
																2006			2007
Operating revenues:
Oil and natural gas	$	33,589		$	22,971		$	21,084		$	44,055		$	59,578		$	22,225		$	37,272
Operating expenses:
Production:
Lease operating		4,536			2,891			2,356			5,247			8,694			3,550			5,536
Workover and other		104			1			4			5			198			9			38
Taxes other than income		2,812			1,843			2,025			3,868			5,606			1,727			3,664
Gathering, transportation and other		188			110			176			286			878			158			824
Impairment expense		—			—			15,258			15,258			53,190			—			—
General and administrative		4,802			2,685			1,578			4,263			4,683			1,711			2,873
Depletion, depreciation and amortization		6,942			3,897			6,659			10,556			23,740			7,052			13,034
Total operating expenses		19,384			11,427			28,056			39,483			96,989			14,207			25,969
Income (loss) from operations		14,205			11,544			(6,972	)		4,572		$	(37,411	)		8,018			11,303
Interest expense and other		(9,894	)		(6,205	)		(1,799	)		(8,004	)		(18,953	)		(7,442	)		(11,882	)
Income (loss) before income taxes	$	4,311		$	5,339		$	(8,771	)	$	(3,432	)	$	(56,364	)	$	576		$	(579	)
Income tax provision		—			—			—			—			(714	)		(576	)	$	(50	)
Net income (loss)	$	4,311		$	5,339		$	(8,771	)	$	(3,432	)	$	(57,078	)	$	—		$	(629	)
Adjusted EBITDA	$	21,147		$	15,441		$	14,945		$	30,386		$	39,519		$	15,070		$	24,337
Balance sheet data (at period end):
Working capital (deficit)	$	(1,611	)				$	1,139					$	(251	)				$	2,756
Total assets		120,266						360,477						604,354						598,475
Long-term debt		95,363						198,737						269,337						269,625
Owner’s equity		19,769						156,425						320,955						317,552
Cash flow data:
Net cash provided by (used in):
Operating activities	$	10,396		$	7,100		$	11,319		$	18,419		$	15,292		$	7,223		$	11,306
Investing activities		(37,199	)		(9,712	)		(442	)		(10,154	)		(311,683	)		(6,311	)		(8,532	)
Financing activities		26,803			2,612			(10,877	)		(8,265	)		296,391			(912	)		(2,774	)

(1) Historical results of operations for the year ended December 31, 2005 have been divided into two periods. The first period from January 1, 2005 to July 27, 2005 represents the period of time prior to Petrohawk Energy Corporation’s ownership of HK Energy Partners LP Predecessor. The second period from July 28, 2005 to December 31, 2005 reflects the results of operations of HK Energy Partners LP Predecessor including the impact of Petrohawk’s purchase accounting adjustments as of July 28, 2005, the date of its acquisition of Mission Resources Corporation. Fiscal 2005 Combined reflects the addition of amounts for predecessor period from January 1, 2005 to July 27, 2005 and successor period from July 28, 2005 to December 31, 2005.

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	Pro Forma as Adjusted HK Energy Partners LP
	Year Ended December 31, 2006(1)			Six Months Ended June 30, 2007(1)
Operating revenues:
Oil and natural gas	$	78,285		$	37,272
Operating expenses:
Production:
Lease operating		10,328			5,536
Workover and other		247			38
Taxes other than income		7,467			3,664
Gathering, transportation and other		1,483			824
Impairment expense		53,190			—
General and administrative		5,723			2,861
Depletion, depreciation and amortization		30,617			13,034
Total operating expenses		109,055			25,957
(Loss) income from operations		(30,770	)		11,315
Interest expense and other		(5,042	)		(2,521	)
(Loss) income before income taxes	$	(35,812	)	$	8,794
Income tax provision		(714	)		(50	)
Net (loss) income	$	(36,526	)	$	8,744
Pro forma net (loss) income per limited partner unit	$	(2.36	)	$	0.57
Adjusted EBITDA	$	53,037		$	24,349
Balance sheet data (at period end):
Working capital				$	171,747
Total assets					766,940
Long-term debt					223,120
Owners’ equity					531,513

(1) The unaudited pro forma results of operations for the year ended December 31, 2006 and for the six months ended June 30, 2007 are presented above to illustrate the approximate pro forma effects on HK Energy Partners LP Predecessor’s results of operations under the purchase method of accounting as if HK Energy Partners LP Predecessor had completed the acquisition of KCS Energy, Inc.’s oil and gas properties on January 1, 2006.

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Adjusted EBITDA

We use EBITDA, adjusted as described below, which we refer to in this prospectus as Adjusted EBITDA, as a supplemental measure of our performance that is not required by, or presented in accordance with, GAAP. We define Adjusted EBITDA as net income plus (i) impairment expense, (ii) depletion, depreciation, and amortization, (iii) interest expense and other, and (iv) income taxes. We present Adjusted EBITDA because we consider it an important supplemental measure of our performance, in particular because it excludes amounts that do not relate directly to our operating performance. Because the use of Adjusted EBITDA facilitates comparisons of our historical operating performance on a more consistent basis, we use this measure for business planning and analysis purposes, in assessing acquisition opportunities and in determining how potential external financing sources are likely to evaluate our business.

Adjusted EBITDA is not a measurement of our financial performance under GAAP and should not be considered as an alternative to net income, operating income or any other performance measure derived in accordance with GAAP, as an alternative to cash flow from operating activities or as a measure of our liquidity. You should not assume that the Adjusted EBITDA amounts shown in this prospectus are comparable to Adjusted EBITDA amounts disclosed by other companies. In evaluating Adjusted EBITDA, you should be aware that it excludes expenses that we will incur in the future on a recurring basis.

Adjusted EBITDA has limitations as an analytical tool, and you should not consider it in isolation. Some of its limitations are:

• it does not reflect our cash expenditures for capital expenditures;

• it does not reflect our significant interest expense, or the cash requirements necessary to service interest or principal payments on our indebtedness; and

• although depletion, depreciation, and amortization are non-cash charges, the assets being depreciated and amortized will often have to be replaced in the future, and Adjusted EBITDA does not reflect the cost or cash requirements for such replacements.

We compensate for these limitations by relying primarily on our GAAP results and using Adjusted EBITDA only supplementally. For more information, see our combined financial statements and the notes to those statements included elsewhere in this prospectus. The following table reconciles our net income before income taxes to our Adjusted EBITDA on a historical and pro forma basis as of the dates shown:

	Predecessor				Successor														Pro Forma as Adjusted HK Energy Partners LP
(In thousands)	Year Ended December 31, 2004		Period from January 1, 2005 to July 27, 2005		Period from July 28, 2005 to December 31, 2005			Fiscal 2005 Combined(1)			Year Ended December 31, 2006			Six Months Ended June 30,					Year Ended December 31, 2006			Six Months Ended June 30, 2007
														2006		2007
Net (loss) income	$	4,311	$	5,339	$	(8,771	)	$	(3,432	)	$	(57,078	)	$	—	$	(629	)	$	(36,526	)	$	8,744
Impairment expense		—		—		15,258			15,258			53,190			—		—			53,190			—
Depletion, depreciation and amortization		6,942		3,897		6,659			10,556			23,740			7,052		13,034			30,617			13,034
Interest expense and other		9,894		6,205		1,799			8,004			18,953			7,442		11,882			5,042			2,521
Income tax provision		—		—		—			—			714			576		50			714			50
Adjusted EBITDA	$	21,147	$	15,441	$	14,945		$	30,386		$	39,519		$	15,070	$	24,337		$	53,037		$	24,349

(1) Historical results of operations for the year ended December 31, 2005 have been divided into two periods. The first period from January 1, 2005 to July 27, 2005 represents the period of time prior to Petrohawk Energy Corporation’s ownership of HK Energy Partners LP Predecessor. The second period from July 28, 2005 to December 31, 2005 reflects the results of operations of HK Energy Partners LP Predecessor including the impact of Petrohawk’s purchase accounting adjustments as of July 28, 2005, the date of its acquisition of Mission Resources Corporation. Fiscal 2005 Combined reflects the addition of amounts for predecessor period from January 1, 2005 to July 27, 2005 and successor period from July 28, 2005 to December 31, 2005.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS

The following discussion and analysis should be read in conjunction with the “Selected Historical and Pro Forma Financial and Operating Data” and the accompanying financial statements and related notes included elsewhere in this prospectus. The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, market prices for oil and natural gas, production volumes, estimates of proved reserves, capital expenditures, economic and competitive conditions, regulatory changes and other uncertainties, as well as those factors discussed below and elsewhere in this prospectus, particularly in “Risk Factors” and “Forward-Looking Statements,” all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur.

Overview

We are a growth oriented Delaware limited partnership formed in October 2007 by Petrohawk Energy Corporation (NYSE: HK) to acquire, develop and exploit oil and natural gas properties. Our properties are primarily located in the Permian Basin region in West Texas and southeastern New Mexico. Our primary business objective is to generate stable cash flows through maintaining our current production levels and asset base over the long term in a manner that will allow us to make quarterly cash distributions to our unitholders at the minimum quarterly distribution rate of $0.35 per unit and, over time, to grow our production and asset base to increase our quarterly cash distribution rate. Our estimated proved reserves consist of 107 Bcfe of the reserves Petrohawk originally acquired from Mission Resources Corporation in July 2005 and 38 Bcfe of the reserves Petrohawk originally acquired from KCS Energy, Inc. in July 2006 (the “KCS Acquisition”).

As described in “Prospectus Summary — Formation Transactions and Partnership Structure,” we will acquire all of the oil and natural gas properties (the “partnership properties”) comprising HK Energy Partners LP Predecessor prior to closing. Our historical financial statements have been derived from the combined financial statements of HK Energy Partners LP Predecessor included elsewhere in this prospectus. The historical financial statements of HK Energy Partners LP Predecessor represent a “carve-out” of the partnership properties from the consolidated financial statements of Mission for the period from January 1, 2004 through July 27, 2005 and from the consolidated financial statements of Petrohawk for the period from July 28, 2005 through June 30, 2007.

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.

How We Evaluate Our Operations

We use a variety of financial and operational measures to assess our performance. Among these measures are the following:

• Volumes of oil and natural gas produced;

• Realized prices;

• Derivative instruments and hedging activities;

• Oil and natural gas operating costs;

• Production and ad valorem taxes; and

• General and administrative expenses.

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Volumes of Oil and Natural Gas Produced

The following table presents historical production volumes for our properties for the years ended December 31, 2004, 2005 and 2006 and for the six months ended June 30, 2006 and 2007:

	Predecessor		Successor
	Year Ended December 31, 2004	Period from January 1, 2005 to July 27, 2005(2)	Period from July 28, 2005 to December 31, 2005(2)	Year Ended December 31, 2005(2)	Year Ended December 31, 2006	Six Months Ended June 30,
2006						2007
Production:
Natural gas (MMcf)(1)	3,518	1,957	1,662	3,620	5,646	1,785	3,746
Oil (MBbl)	402	226	160	386	356	176	171
Total production (MMcfe)	5,929	3,315	2,621	5,936	7,780	2,841	4,772
Average daily production (MMcfe/d)	16.2	15.9	25.3	16.3	21.3	15.6	26.3

(1) Includes NGL volumes calculated using natural gas equivalents of six Mcf of natural gas per Bbl of oil or NGL.

(2) Historical results of operations for the year ended December 31, 2005 have been divided into two periods. The first period from January 1, 2005 to July 27, 2005 represents the period of time prior to Petrohawk Energy Corporation’s ownership of HK Energy Partners LP Predecessor. The second period from July 28, 2005 to December 31, 2005 reflects the results of operations of HK Energy Partners LP Predecessor including the impact of Petrohawk’s purchase accounting adjustments as of July 28, 2005, the date of its acquisition of Mission Resources Corporation.

Realized Prices

Factors Affecting the Price of Crude Oil and Natural Gas at the Wellhead. We market our oil and natural gas production to a variety of purchasers based on regional pricing. The relative value of natural gas and crude oil at the wellhead is determined by two main factors: quality and location relative to consuming and refining markets.

• Natural Gas Prices. The NYMEX futures price of natural gas is a widely used benchmark in the pricing of natural gas in the United States. The principal characteristics of natural gas affecting its price are (1) the Btu content of the natural gas, which is a measure of its heating value, (2) the percentage of the sulfur and/or carbon dioxide content in the natural gas, by volume, and (3) the proximity of the natural gas to major consuming markets.

• Crude Oil Prices. The NYMEX futures price of crude oil is a widely used benchmark in the pricing of domestic and imported crude oil in the United States. Several factors impact the price of crude oil, including the quality of the crude oil and the proximity to major consuming markets. The principal characteristics affecting the price of crude oil are (1) the API gravity, which determines the value of the products that can be refined from the oil, (2) the sulfur content of the crude oil and (3) the proximity of the crude oil production to major consuming and refining markets.

Derivative Instruments and Hedging Activities

An important part of our business strategy includes hedging a portion of our oil and natural gas production to reduce our exposure to fluctuations in the prices of oil and natural gas and achieve a more predictable cash flow. As of October 25, 2007, Petrohawk has entered into swap agreements covering 3,660,000 MMBtu of natural gas and 275 MBbls of oil representing approximately 56% of our forecasted total production of 25.7 MMcfe/d for the twelve months ended December 31, 2008, and will assign those derivative contracts to us at the closing of this offering. Petrohawk anticipates entering into additional derivative contracts (to be assigned to us at the closing of this offering)

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so that approximately 80% to 85% of our estimated net production of oil and gas from proved developed producing reserves will be covered by derivatives through December 31, 2010. The form of these derivatives is expected to be fixed-price swaps and puts. By removing a portion of price volatility associated with our future oil and natural gas production we have mitigated, but not eliminated, the potential effects of changing oil and natural gas prices on our cash flows from operations for those periods. Despite our anticipated hedging activities, we remain subject to the impact of regional basis price differentials, which may be material. See “— Quantitative and Qualitative Disclosures About Market Risk” and “Our Cash Distribution Policy and Restrictions on Distributions — Operations and Revenue.”

Oil and Natural Gas Operating Costs

Oil and natural gas operating costs are the costs incurred in the operation of producing oil and natural gas properties. Typically, direct labor, utilities, materials and supplies, chemicals and water injection and disposal are significant components of our oil and natural gas operating costs. We typically evaluate our oil and natural gas operating costs on a per Mcfe basis. This unit rate allows us to monitor these costs in certain fields and geographic areas to identify trends and to benchmark against other producers.

Production and Ad Valorem Taxes

Production taxes are set by state and local governments and vary as to the tax rate and value to which that rate is applied. Ad valorem taxes are based partially on the value of oil and natural gas reserves, which can fluctuate significantly based on commodity prices. Due to volatility in the prices of oil and natural gas, the values upon which ad valorem taxes in certain states are computed can vary significantly between periods. We typically evaluate our production and ad valorem taxes as a percentage of revenue (before the impact of derivative financial instruments).

General and Administrative Expenses

General and administrative expenses represent all other costs which cannot be specifically assigned to a producing oil and natural gas property, but are essential to managing and administering our assets and business. The majority of general and administrative expenses are represented by salaries and related personnel benefits, office rents and information technology related expenses.

Outlook

Significant factors that may impact future commodity prices include developments in the issues currently impacting Iraq and Iran, in particular, and the Middle East in general; the extent to which members of the Organization of Petroleum Exporting Countries (“OPEC”) and other oil exporting nations are able to continue to manage oil supply through export quotas; and overall North American gas supply and demand fundamentals, including the impact of increasing liquefied natural gas (“LNG”) deliveries to the United States. Although we cannot predict the occurrence of events that will affect future commodity prices or the degree to which these prices will be affected, the prices for any commodity that we produce will generally approximate market prices in the geographic region of the production.

In order to address, in part, volatility in commodity prices, we have implemented a commodity price risk management program that is intended to reduce the volatility in our revenues. Under that program, we have adopted a policy that contemplates hedging the prices for approximately 80% to 85% of our estimated net production of oil and natural gas from proved developed producing reserves for a period of at least three years. Implementation of this policy will mitigate, but will not eliminate, our sensitivity to short-term changes in commodity prices. See “— Quantitative and Qualitative Disclosures About Market Risk.”

We expect to primarily fund our 2008 maintenance capital expenditures with cash flow from operations. We believe that we will have sufficient cash flow from operations after funding these capital expenditures to enable

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us to make our minimum quarterly distribution to unitholders for each quarter for the twelve months ending December 31, 2008. We plan to reserve a portion of our cash flow from operations to pursue acquisitions of producing oil and natural gas properties both from Petrohawk and third parties. Without making these types of acquisitions, our ability to maintain our quarterly distribution levels will be adversely affected over the long term.

Factors Affecting Comparability of Future Results

The discussion of the results of operations and period-to-period comparisons presented below covers the historical results of HK Energy Partners LP Predecessor for all periods presented. You should read the following discussion in conjunction with the historical and pro forma financial statements included elsewhere in this prospectus. Our future results could differ materially from our historical results due to a variety of factors, including the following:

Derivatives. Neither our financial statements nor the statements of revenues less direct operating expenses of the oil and natural gas properties included within the partnership properties that were originally acquired through the KCS Acquisition (“KCS Properties”) contain any costs related to derivative transactions. Petrohawk intends to enter into derivative contracts covering approximately 80% to 85% of our estimated net production of oil and natural gas from proved developed producing reserves through December 31, 2010, and intends to assign those contracts to us at the closing of this offering. Because we do not intend to elect to designate any derivative positions as cash flow hedges for accounting purposes, we will in the future record the net change in the mark-to-market valuation of these derivative contracts in our combined statement of operations.

Changes in Outstanding Indebtedness. The historical financial statements of HK Energy Partners LP Predecessor include a carve out allocation of a portion of the indebtedness of Mission for the period January 1, 2004 through July 27, 2005 and a carve out allocation of a portion of indebtedness of Petrohawk for the period commencing July 28, 2005 through the periods presented. The amount of debt allocated in the historical financial statements is based upon the ratio of our estimated net proved reserves to those of Mission or Petrohawk, as applicable, during the periods presented. Because subsequent to the closing of the offering of our common units we will not be contractually obligated for Petrohawk’s indebtedness, it is not reflected in the pro forma financial statements herein and will not be reflected in our financial statements following the closing of the offering. As described elsewhere in this prospectus, in connection with the formation transactions we expect to incur indebtedness of approximately $58.1 million under our revolving credit facility and $165.0 million under our term loan facility at the closing of this offering. This indebtedness and related interest expense are reflected in our pro forma financial statements. Any indebtedness we incur, and the related interest and other expense associated with such indebtedness, will be reflected in our financial statements in future periods.

Acquisition of KCS Properties in July 2006. The discussion of our historical results reflects the results of operations attributable to our acquisition of the KCS Properties from the date of the KCS Acquisition forward. Accordingly, results for periods prior to and after our acquisition of the KCS Properties may not be comparable.

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Comparison of Results of Operations

Six Months Ended June 30, 2007 Compared to Six Months Ended June 30, 2006

The following table summarizes key items of comparison and their related increase (decrease) for the six months ended June 30, 2007 and 2006 as indicated.

	Six Months Ended June 30,						Increase (Decrease)
	2007			2006
	(In thousands except per unit and per Mcfe amounts)
Oil and gas sales	$	37,272		$	22,225		$	15,047
Expenses:
Production:
Lease operating		5,536			3,550			1,986
Workover and other		38			9			29
Taxes other than income		3,664			1,727			1,937
Gathering, transportation and other		824			158			666
General and administrative		2,873			1,711			1,162
Depletion, depreciation and amortization:
Depletion — Full cost		12,862			7,004			5,858
Accretion expense		172			48			124
Interest expense and other		11,882			7,442			4,440
(Loss) income before income taxes	$	(579	)	$	576		$	(1,155	)
Income tax provision		(50	)		(576	)		526
Net loss	$	(629	)	$	—		$	(629	)
Production:
Natural Gas — MMcf(1)		3,746			1,785			1,961
Crude Oil — MBbl		171			176			(5	)
Natural Gas Equivalent — MMcfe		4,772			2,841			1,931
Average Daily Production — MMcfe		26.3			15.6			10.7
Average price per unit (excluding hedges):
Gas price per Mcf	$	7.38		$	6.38		$	1.00
Oil price per Bbl		54.88			60.05			(5.17	)
Equivalent per Mcfe		7.76			7.73			0.03
Average cost per Mcfe:
Production:
Lease operating	$	1.16		$	1.25		$	(0.09	)
Workover and other		0.01			0.00			0.01
Taxes other than income		0.77			0.61			0.16
Gathering, transportation and other		0.17			0.06			0.11
General and administrative		0.60			0.60			—
Depletion		2.70			2.47			0.23

(1) Includes NGL volumes calculated using natural gas equivalents of six Mcf of natural gas per Bbl of NGL.

For the six months ended June 30, 2007, oil and natural gas sales increased $15.0 million, from the same period in 2006, to $37.3 million. The increase was primarily due to the increase in production of 1,931 MMcfe related to our acquisition of the KCS Properties on July 12, 2006. Increased production led to a $14.9 million increase in oil and gas revenues complemented by a modest increase in realized commodity prices for the six months ended June 30, 2007.

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Lease operating expenses increased $2.0 million for the six months ended June 30, 2007. The increase was primarily related to an increase in production volumes as a result of the KCS Acquisition, as well as our successful drilling activities in 2007. On a per unit basis, lease operating expenses decreased from $1.25 per Mcfe in 2006 to $1.16 per Mcfe in 2007. The decrease on a per unit basis is primarily due to our continued cost control efforts and our acquisition of lower operating cost properties from KCS.

Taxes other than income increased $1.9 million for the six months ended June 30, 2007 as compared to the same period in 2006. The largest components of taxes other than income are production and severance taxes, which are generally assessed as a percentage of gross oil and natural gas sales. As a percentage of oil and gas sales, taxes other than income increased to 9.8% in 2007 from 7.8% in 2006. This increase as a percentage of oil and gas sales was due to higher severance tax rates in our operating areas as a result of our acquisition of properties from KCS.

Gathering, transportation and other expense increased $0.7 million for the six months ended June 30, 2007 as compared to the same period in 2006. This increase was due primarily to the KCS Acquisition.

Depletion expense increased $5.9 million for the six months ended June 30, 2007 from the same period in 2006 to $12.9 million. Depletion for oil and natural gas properties is calculated using the unit of production method, which essentially depletes the capitalized costs associated with the evaluated properties plus future development costs based on the ratio of production volume for the current period to total remaining reserve volume for the evaluated properties. On a per unit basis, depletion expense increased $0.23 per Mcfe to $2.70 per Mcfe from $2.47 per Mcfe. Both increases were due to the KCS Acquisition.

Interest expense and other increased $4.4 million for the six months ended June 30, 2007 compared to the same period in 2006. This increase was primarily due to additional debt of $71 million we incurred in conjunction with the KCS Acquisition.

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Year Ended December 31, 2006 Compared to Year Ended December 31, 2005 (Combined)(1)

The following table summarizes key items of comparison and their related increase (decrease) for the years ended December 31, 2006 and 2005 as indicated.

	For the Year Ended						Increase (Decrease)
	2006			2005
	(In thousands except per unit and per Mcfe amounts)
Oil and gas sales	$	59,578		$	44,055		$	15,523
Expenses:
Production:
Lease operating		8,694			5,247			3,447
Workover and other		198			5			193
Taxes other than income		5,606			3,868			1,738
Gathering, transportation and other		878			286			592
Impairment expense		53,190			15,258			37,932
General and administrative		4,683			4,263			420
Depletion, depreciation and amortization:
Depletion — Full cost		23,536			10,518			13,018
Accretion expense		204			38			166
Interest expense and other		18,953			8,004			10,949
Loss before income taxes		(56,364	)		(3,432	)		(52,932	)
Income tax provision		(714	)		—			(714	)
Net loss	$	(57,078	)	$	(3,432	)	$	(53,646	)
Production:
Natural Gas — MMcf(2)		5,646			3,620			2,026
Crude Oil — MBbl		356			386			(30	)
Natural Gas Equivalent — MMcfe		7,780			5,936			1,844
Average Daily Production — MMcfe		21.3			16.3			5.0
Average price per unit (excluding hedges):
Gas price per Mcf	$	6.72		$	6.64		$	0.08
Oil price per Bbl		58.95			50.82			8.13
Equivalent per Mcfe		7.58			7.35			0.23
Average cost per Mcfe:
Production:
Lease operating	$	1.12		$	0.88		$	0.24
Workover and other		0.03			—			0.03
Taxes other than income		0.72			0.65			0.07
Gathering, transportation and other		0.11			0.05			0.06
General and administrative		0.60			0.72			(0.12	)
Depletion		3.02			1.77			1.25

(1) The results for the year ended December 31, 2005 reflect the sum of (i) the carve out from Mission Resources Corporation of HK Energy Partners LP Predecessor’s results of operations for the period from January 1, 2005 to July 27, 2005 and (ii) the carve out from Petrohawk Energy Corporation of HK Energy Partners LP Predecessor’s results of operations for the period from July 28, 2005 to December 31, 2005, which reflects a step-up in basis as a result of Petrohawk’s acquisition of Mission. The combined results of operations of our predecessor for the year ended December 31, 2005 do not necessarily represent the results that would have been achieved during this period had the partnership properties been operated by Petrohawk for the entire period.

(2) Includes NGL volumes calculated using natural gas equivalents of six Mcf of natural gas per Bbl of oil or NGL.

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For the year ended December 31, 2006, oil and natural gas sales increased $15.5 million, from the same period in 2005, to $59.6 million. Total 2006 production was 7,780 MMcfe, an increase of 1,844 MMcfe from 2005 production of 5,936 MMcfe. Increased production accounted for approximately 88%, or $13.6 million, of the $15.5 million increase in oil and gas sales. Our realized average price per Mcfe increased $0.23 in 2006 to $7.58 from $7.35 in 2005 which also contributed to the increase in oil and natural gas sales.

Lease operating expenses increased $3.4 million from the prior year. The increase was primarily due to a continued increase in overall activity in 2006. We drilled 44 gross wells in 2006 compared to 21 gross wells in 2005. On a per unit basis, lease operating expenses increased 27% from $0.88 per Mcfe in 2005 to $1.12 per Mcfe in 2006. The increase on a per unit basis is primarily due to an overall increase in drilling and production costs.

Taxes other than income increased $1.7 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. As a percentage of oil and natural gas sales, taxes other than income increased from 8.8% in 2005 to 9.4% in 2006. This increase as a percentage of oil and gas sales was due to the higher severance tax rates in our operating areas as a result of our acquisition of properties from KCS.

Gathering, transportation and other expense increased $0.6 million for the year ended December 31, 2006 as compared to the same period in 2005. This increase was due primarily to the KCS Acquisition.

Impairment expense increased $37.9 million for the year ended December 31, 2006 as compared to the same period in 2005. This increase was primarily due to the economic impact on our reserves valuation of higher commodity prices at December 31, 2006 as compared to December 31, 2005, and as a result of our acquisition of oil and gas assets from KCS. See “— Critical Accounting Policies and Estimates” for more details on our application of the full cost method of accounting and the related calculation of the limitation on capitalized costs.

Depletion expense increased $13.0 million to $23.5 million for the year ended December 31, 2006 as compared to the same period in 2005. 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 $1.25 per Mcfe to $3.02 from $1.77. This increase was due primarily to the KCS Acquisition.

Interest expense and other increased $10.9 million for the year ended December 31, 2006 compared to the same period in 2005. This increase was due primarily to additional debt of $71 million we incurred in conjunction with the KCS Acquisition.

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Year Ended December 31, 2005 (Combined)(1) Compared to Year Ended December 31, 2004

The following table summarizes key items of comparison and their related increase (decrease) for the years ended December 31, 2005 and 2004 as indicated.

	For the Year Ended					Increase (Decrease)
	2005(1)			2004
	(In thousands except per unit and per Mcfe amounts)
Oil and gas sales	$	44,055		$	33,589	$	10,466
Expenses:
Production:
Lease operating		5,247			4,536		711
Workover and other		5			104		(99	)
Taxes other than income		3,868			2,812		1,056
Gathering, transportation and other		286			188		98
Impairment expense		15,258			—		15,258
General and administrative		4,263			4,802		(539	)
Depletion, depreciation and amortization:
Depletion — Full cost		10,518			6,928		3,590
Accretion expense		38			14		24
Interest expense and other		8,004			9,894		(1,890	)
(Loss) income before income taxes	$	(3,432	)	$	4,311	$	(7,743	)
Income tax provision		—			—		—
Net (loss) income	$	(3,432	)	$	4,311	$	7,743
Production:
Natural Gas — MMcf(2)		3,620			3,518		102
Crude Oil — MBbl		386			402		(16	)
Natural Gas Equivalent — MMcfe		5,936			5,929		7
Average Daily Production — MMcfe		16.3			16.2		—
Average price per unit (excluding hedges):
Gas price per Mcf	$	6.64		$	5.10	$	1.54
Oil price per Bbl		50.82			37.98		12.84
Equivalent per Mcfe		7.35			5.60		1.75
Average cost per Mcfe:
Production:
Lease operating	$	0.88		$	0.76	$	0.12
Workover and other		—			0.02		(0.02	)
Taxes other than income		0.65			0.47		0.18
Gathering, transportation and other		0.05			0.03		0.02
General and administrative		0.72			0.81		(0.09	)
Depletion		1.77			1.17		0.60

(1) The results for the year ended December 31, 2005 reflect the sum of (i) the carve out from Mission Resources Corporation of HK Energy Partners LP Predecessor’s results of operations for the period from January 1, 2005 to July 27, 2005 and (ii) the carve out from Petrohawk Energy Corporation of HK Energy Partners LP Predecessor’s results of operations for the period from July 28, 2005 to December 31, 2005, which reflects a step-up in basis as a result of Petrohawk’s acquisition of Mission. The combined results of operations of our predecessor for the year ended December 31, 2005 do not necessarily represent the results that would have been achieved during this period had the partnership properties been operated by Petrohawk for the entire period.

(2) Includes NGL volumes calculated using natural gas equivalents of six Mcf of natural gas per Bbl of NGL.

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For the year ended December 31, 2005, oil and natural gas sales increased $10.5 million, from the same period in 2004, to $44.1 million. The increase for the year was primarily due to the increase in energy prices. Higher commodity prices led to an approximate $10.4 million increase in revenues from the prior year as our realized average price per Mcfe increased $1.75 in 2005 to $7.35 from $5.60 in 2004. Production remained constant at 5.9 Bcfe in 2005 and 2004.

Lease operating expenses increased $0.7 million from the prior year. The increase was primarily due to our increase in overall activity in 2005. On a per unit basis, lease operating expenses increased approximately 16% from $0.76 per Mcfe in 2004 to $0.88 per Mcfe in 2005. The increase was due primarily to higher drilling and production costs.

Taxes other than income increased $1.1 million for the year ended December 31, 2005 as compared to the same period in 2004. A significant component of such increase related to production taxes which are generally assessed as a percentage of gross oil and natural gas sales. In general, production taxes increase as revenue and production increase. As a percentage of oil and natural gas sales, taxes other than income increased from 8.4% in 2004 to 8.8% in 2005.

We recorded a full cost ceiling impairment of $15.3 million for the year ended December 31, 2005. We did not have an impairment for the year ended December 31, 2004. Our 2005 impairment was primarily due to the step up in basis of our oil and gas properties resulting from Petrohawk’s acquisition of Mission as of July 28, 2005 as well as various other economic factors that impact our reserves valuation. Refer to “— Critical Accounting Policies and Estimates” for more details on our application of the full cost method of accounting and the related calculation of the limitation on capitalized costs.

Depletion expense increased $3.6 million from the same period in 2004 to $10.5 million for the year ended December 31, 2005. 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 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 51% from $1.17 to $1.77. This increase was due primarily to the impact of Petrohawk’s acquisition of Mission on July 28, 2005 and the impact of the related purchase accounting.

Interest expense and other decreased $1.9 million for the year ended December 31, 2005 compared to the same period in 2004. This decrease was primarily due to the decrease in interest rates prior to our acquisition of Mission in July 2005, partially offset by our increase in long-term debt.

Capital Resources and Liquidity

Our sources of cash for the six months ended June 30, 2007 and 2006 were solely from operating activities. Net income before non-cash adjustments was offset by cash used in investing activities to fund our drilling programs. Operating cash flow fluctuations were substantially driven by changes in our average daily production and higher average price per unit of natural gas. Prices for oil and natural gas have historically been subject to seasonal and global influences; however, the impact of other risks and uncertainties have influenced prices throughout recent years. Working capital was substantially influenced by all of these variables. Fluctuations in cash flow may result in an increase or decrease in our capital and exploration expenditures. See “Our Cash Distribution Policy and Restrictions on Distributions — Sensitivity Analysis” for a review of the impact of prices and volumes on sales.

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Cash flows provided by operating activities were primarily used to fund exploration and development expenditures. Proceeds from the issuance of long-term debt and cash received from operations in both 2005 and 2006 were offset by cash used in investing activities to complete our acquisition 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 below for additional discussion and analysis of cash flow.

	Year Ended December 31, 2004			Period from January 1, 2005 to July 27, 2005(1)			Period from July 28, 2005 to December 31, 2005(1)			Year Ended December 31, 2005(1)			Year Ended December 31, 2006
	(In thousands)
Net cash provided by operating activities	$	10,396		$	7,100		$	11,319		$	18,419		$	15,292
Net cash used in investing activities		(37,199	)		(9,712	)		(442	)		(10,154	)		(311,683	)
Net cash provided by financing activities		26,803			2,612			(10,877	)		(8,265	)		296,391
Net (decrease) increase in cash	$	—		$	—		$	—		$	—		$	—

(1) The results for the year ended December 31, 2005 reflect the sum of (i) the carve out from Mission Resources Corporation of HK Energy Partners LP Predecessor’s results of operations for the period from January 1, 2005 to July 27, 2005 and (ii) the carve out from Petrohawk Energy Corporation of HK Energy Partners LP Predecessor’s results of operations for the period from July 28, 2005 to December 31, 2005, which reflects a step-up in basis as a result of Petrohawk’s acquisition of Mission. The combined results of operations of our predecessor for the year ended December 31, 2005 do not necessarily represent the results that would have been achieved during this period had the partnership properties been operated by Petrohawk for the entire period.

Operating Activities. Net cash flows provided by operating activities were $15.3 million, $18.4 and $10.4 million for the years ended December 31, 2006, 2005 and 2004, 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 2006 primarily due to our increase in production volumes as a result of the KCS Acquisition as well as our continued drilling success. The increase was partially attributable to a 3% increase in our realized natural gas equivalent price compared to 2005.

Net cash flows provided by operating activities in 2005 increased $8.0 million from 2004. This increase was primarily due to an increase in oil and natural gas revenues in 2005. Average realized prices increased $1.75 from $5.60 per Mcfe in 2004 to $7.35 per Mcfe in 2005. Production volumes increased 7 MMcfe from 5,929 MMcfe in 2004 to 5,936 MMcfe in 2005.

Investing Activities. The primary driver of cash used in investing activities was capital spending, inclusive of acquisitions. Cash used in investing activities was $311.7 million, $10.2 million and $37.2 million for the years ended December 31, 2006, 2005 and 2004, respectively.

During 2006, we spent an additional $238.9 million on capital expenditures in conjunction with our drilling program. We participated in the drilling of 44 wells in 2006, with a success rate of 100%.

Cash used in investing activities was $10.2 million in 2005. Capital spending was primarily related to our drilling of 21 gross wells.

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Cash used in investing activities in 2004 was $37.2 million. This amount is primarily comprised of capital spending and exploration costs of approximately $36.6 million. In 2004, we drilled 48 gross wells.

Financing Activities. Net cash flows provided by financing activities were $296.4 million, $8.3 million, and $26.8 million for the years ended December 31, 2006, 2005 and 2004, respectively. Net cash used in financing activities represents the pass-through of our net cash flow to Petrohawk prior to the July 2005 Mission and July 2006 KCS acquisitions, and net cash provided by financing activities represents the contribution to us by Petrohawk of the net cash required for principal and interest on allocated parent debt following the Mission and KCS acquisitions.

If cash flow from operations does not meet our expectations, we believe that we will have the ability to finance through new debt or equity offerings, if necessary, our capital requirements, including acquisitions. We may also reduce our anticipated level of capital expenditures, acquisitions, or both. We cannot assure you that needed capital will be available on acceptable terms or at all. Our ability to raise funds through the incurrence of additional indebtedness will be limited by covenants in our credit agreements. If we are unable to obtain funds when needed or on acceptable terms, we may not be able to complete acquisitions that may be favorable to us or finance the capital expenditures necessary to replace our reserves.

Future Capital Expenditures. For the twelve months ending December 31, 2007, we estimate that our total capital expenditures will be approximately $14.0 million, which we anticipate will result in maintaining our production level essentially flat throughout 2007 at approximately 26 MMcfe/d. We estimate that our actual expenditures for development activities for the twelve months ending December 31, 2008 will be approximately $16 million as compared to $32.8 million and $20.9 million on a pro forma basis for the twelve months ended December 31, 2006 and June 30, 2007, respectively. This anticipated decrease is the result of lower levels of budgeted development drilling in the forecast period.

We anticipate replacing declining production and reserves through the drilling and completing of wells on our current properties and through the acquisition of producing and non-producing oil and natural gas properties from Petrohawk and from third parties. In our forecast for the twelve months ending December 31, 2008, we project estimated maintenance capital expenditures of $18.8 million. Of this amount, approximately $16 million represents identified development drilling and workover projects. We estimate that we will drill and complete 7 gross (6.9 net) operated wells and 40 gross (5.2 net) non-operated development wells during 2008 at an aggregate cost of approximately $5.4 million and $4 million, respectively. The remaining $6.6 million of our budgeted capital expenditures for the twelve months ending December 31, 2008 consists of workover projects. Although the approximately $16 million to be spent in 2008 is expected to enable us to achieve our 2008 forecasted daily production rate, the remaining $2.8 million of estimated maintenance capital expenditures will be reserved for either acquisitions or increased drilling in future periods so that we can maintain our current production levels and asset base over the long term.

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Contractual Obligations

The following has been presented as adjusted to reflect this offering and the other transactions described under “Prospectus Summary — Formation Transactions and Partnership Structure.” We have no material long- term commitments associated with our capital expenditure plans or operating agreements. Consequently, we believe we have a significant degree of flexibility to adjust the level of such expenditures as circumstances warrant. Our level of capital expenditures will vary in future periods depending on the success we experience in our acquisition, developmental and exploration activities, oil and natural gas price conditions and other related economic factors. Currently no sources of liquidity or financing are provided by off-balance sheet arrangements or transactions with unconsolidated, limited-purpose entities. Prior to closing this offering we expect to enter into a $305 million revolving and term credit facility, discussed below. The following table summarizes these expected contractual obligations and commitments by payment periods (in thousands).

	Payments Due by Period
Contractual Obligations	Total		Less than one year		2-3 years		4-5 years		More than 5 years
Revolving credit facility	$	58,120	$	—	$	—	$	58,120	$	—
Term debt		165,000		—		165,000		—		—
Interest expense on long-term debt		40,935		13,929		18,288		8,718		—
Total contractual obligations	$	264,055	$	13,929	$	183,288	$	66,838	$	—

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 June 30, 2007 is $6.6 million.

Credit Facility

Prior to closing this offering, we expect to enter into a $305 million credit facility, which we expect will include both term and revolving borrowing capacity. Upon the closing of this offering, the credit facility will be available for general partnership purposes, including working capital, capital expenditures and acquisitions. We expect that we will incur approximately $165.0 million of term borrowings and $58.1 million of revolving borrowings under our credit facility at the closing of this offering. As a result, we expect to have approximately $82 million of remaining borrowing capacity immediately after the closing.

We expect the credit facility to have a five year term unless extended. Revolving loans under the credit agreement are subject to varying rates of interest based on (1) the total amount outstanding under the credit agreement in relation to the borrowing base and (2) whether the loan is a Eurodollar loan or a base rate loan. Eurodollar loans bear interest at the Eurodollar rate plus the applicable margin indicated in the following table, and base rate loans bear interest at the base rate plus the applicable margin indicated in the following table:

Ratio of Total Outstandings to Borrowing Base	Applicable Margin for Eurodollar Loans			Applicable Margin for Base Rate Loans
Less than .50 to 1		1.00	%	—
Greater than or equal to .50 to 1 but less than .75 to 1		1.25	%	—
Greater than or equal to .75 to 1 but less than .90 to 1		1.50	%	0.125	%
Greater than or equal to .90 to 1		1.75	%	0.125	%

We will distribute proceeds from approximately $165.0 million in term borrowings and $58.1 million in revolving borrowings to subsidiaries of Petrohawk in partial consideration for the assets contributed to us upon

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the closing of this offering. The term borrowings will be secured by an equal amount of qualifying investment grade securities we purchase with the proceeds from this offering.

Availability under the revolving portion of our credit facility is subject to a borrowing base, which we expect to be initially set at $140 million. The borrowing base is subject to semi-annual redeterminations. The lenders will also have the right to require one additional redetermination in any calendar year. Our obligations under the revolving portion of our credit facility will be secured by liens on substantially all of our assets and term borrowings will be secured at all times by qualifying investment grade securities in an amount equal to or greater than the outstanding principal amount of the term loan. We will be allowed to prepay all loans under the credit facility in whole or in part from time to time without a premium or penalty, subject to certain restrictions in the credit facility. Upon any prepayment of term borrowings, the amount of the revolving portion of our credit facility will be automatically increased to the extent that the repayment of our term borrowings is made in connection with a permitted acquisition or permitted capital expenditure. Indebtedness under the credit facility will rank senior to all our future subordinated debt.

The credit facility will prohibit us from making distributions of available cash to unitholders if any default or event of default (as defined in the credit facility) exists. Such events of default include, among others, a default in the due performance or observance of the covenants discussed below. In addition, the credit facility will contain covenants limiting our ability to make other restricted distributions or dividends on account of the purchase, redemption, retirement, acquisition, cancellation or termination of partnership interests; incur additional indebtedness; grant liens or make certain negative pledges; make certain loans or investments; engage in transactions with affiliates; make any material change to the nature of our business; make a disposition of assets; or enter into a merger, consolidate, liquidate, wind up or dissolve.

In addition, the credit facility will contain financial covenants requiring us to maintain:

• an interest coverage ratio (the ratio of our consolidated EBITDA to our consolidated interest expense (net of interest income), in each case as defined in the credit agreement) of not less than 2.5 to 1.0, determined as of the last day of each quarter for the four-quarter period ending on the date of determination; and

• a current ratio (the ratio of our consolidated current assets plus unused availability under the credit agreement to our consolidated current liabilities, in each case as defined in the credit agreement) to be not less than 1.0 to 1.0.

If an event of default exists under the credit facility, the lenders will be able to accelerate the maturity of all borrowings under the credit facility and demand repayment of amounts outstanding.

We expect that upon the completion of this offering and our application of the proceeds of this offering and the borrowings under our credit facility we will be in material compliance with all of the covenants under our credit facility and that we will be permitted to make distributions of available cash to our unitholders in accordance with the terms of our partnership agreement.

Off-Balance Sheet Arrangements

At June 30, 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 development activities, excluding acquisitions, with cash generated from operations and, when necessary, with borrowings under our credit facility. We budget these capital expenditures based on our projected cash flows for the year. We have budgeted $14 million in capital expenditures for 2007, of which $7 million has been spent as of June 30, 2007. We have budgeted capital

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expenditures of $18.8 million for 2008, which includes $16 million in identified drilling and workover projects with the balance reserved for either acquisitions or increased drilling in future periods so that we can maintain our current production level and our asset base over the long term.

Quantitative and Qualitative Disclosures About Market Risks

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. Our risk management policy provides for the use of derivative instruments to manage these risks. The types of derivative instruments that we may utilize include futures, swaps and options. The volume of derivative instruments that we may utilize is governed by our 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.

There were no derivative financial instruments allocable to the carve out properties at June 30, 2007. The table below shows the volumes and prices of Petrohawk’s derivative financial instruments for 2008 through 2010 that were in place as of October 25, 2007 and will be assigned to us at the closing of this offering. For the 2008 calendar year, approximately 66% of our forecasted natural gas production (excluding NGLs) and 83% of our forecasted oil production are covered by derivatives. Petrohawk intends to enter into additional derivative contracts (to be assigned to us upon consummation of this offering) so that approximately 80% to 85% of our estimated net production of oil and gas from proved developed producing reserves will be covered by derivatives through December 31, 2010.

	Swaps
	MMBtu	Weighted Average Price
Natural Gas:
January 2008 — December 2008	3,660,000	$	8.25
January 2009 — December 2009	3,660,000	$	8.46
January 2010 — December 2010	3,660,000	$	8.25
	MBbls	Weighted Average Price
Oil:
January 2008 — December 2008	275	$	81.17
January 2009 — December 2009	275	$	77.00
January 2010 — December 2010	275	$	75.28

Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations are based upon our financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America. The preparation of our 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 financial statements. Described below are the most significant policies we apply in preparing our 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 Note 2, “Summary of Significant Accounting Policies”of the audited financial statements of the HK Energy Partners LP Predecessor included elsewhere in this prospectus, for a discussion of additional accounting policies and estimates made by management.

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Oil and Natural Gas Activities

Accounting for oil and natural gas activities is subject to special, 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 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 SEC guidelines. Our engineering estimates of proved oil and natural gas reserves directly impact financial accounting estimates, including depletion, depreciation 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 as of June 30, 2007 and as of the years ended December 31, 2006, 2005 and 2004 were prepared by Netherland, Sewell & Associates, Inc., an independent oil and natural gas reservoir engineering consulting firm.

Depletion, Depreciation and Amortization

Our rate of recording depletion, depreciation and amortization expense (DD&A) is 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

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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.

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 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 unitholders’ 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.

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 will 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.

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Effective January 1, 2002, we adopted SFAS No. 142, Goodwill and Other Intangible Assets, under which goodwill is no longer 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 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 2006. No impairment was deemed necessary. Downward revisions of estimated proved 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.

Revenue Recognition

We recognize oil and natural gas sales upon delivery to the purchaser. Under the sales method, we and other joint owners may sell more or less than their entitled share of the natural gas volume produced. Should our excess sales of natural gas exceed our share of estimated remaining recoverable reserves, we record a liability and revenue is deferred.

Recently Issued Accounting Standards

We discuss recently adopted and issued accounting standards in Note 2, “Summary of Significant Accounting Policies”of the audited combined financial statements of the HK Energy Partners LP Predecessor included elsewhere in this prospectus.

Interest Sensitivity

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

At June 30, 2007, total pro forma debt was $223.1 million, of which approximately 26%, or $58.1 million, bears interest at an estimated weighted average variable interest rate of 7.5% per year. The remaining 74% of our total debt balance at June 30, 2007, or $165.0 million, bears interest at an estimated weighted average variable interest rate of 5.8% per year. Fluctuations in market interest rates will cause our annual interest costs to fluctuate. If the balance of our bank debt at June 30, 2007 were to remain constant, a 1% increase in market interest rates would increase our interest expense by approximately $2.2 million annually.

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BUSINESS

Overview

We are a growth oriented Delaware limited partnership formed in October 2007 by Petrohawk Energy Corporation (NYSE: HK) to acquire, develop and exploit oil and natural gas properties. Our properties are primarily located in the Permian Basin region in West Texas and southeastern New Mexico.

At June 30, 2007, our oil and natural gas properties had estimated net proved reserves of 145.3 Bcfe, of which approximately 72% were natural gas and 79% were proved developed. For the six months ended June 30, 2007, on a pro forma combined basis, our properties produced approximately 26.3 MMcfe/d. Our producing properties are located in mature fields that exhibit relatively long-lived production, with a reserve to production ratio of 15 years, based on our estimated proved reserves as of June 30, 2007 and our annualized production for the six months ended June 30, 2007.

Our primary business objective is to generate stable cash flows through maintaining our current production levels and asset base over the long term in a manner that will allow us to make quarterly cash distributions to our unitholders at the minimum quarterly distribution rate of $0.35 and, over time, to grow our production and asset base to increase our quarterly cash distribution rate. We intend to rely on the significant operating and acquisition experience of Petrohawk’s management team, acting for our general partner, to execute our growth strategy. Subsequent to the arrival of Petrohawk’s current management in May 2004, Petrohawk increased its proved reserves from approximately 219 Bcfe as of December 31, 2004 to approximately 1,076 Bcfe as of December 31, 2006 and increased its average daily production from approximately 29 MMcfe/d for the three month period ended December 31, 2004 to approximately 321 MMcfe/d for the six month period ended June 30, 2007, primarily through strategic acquisitions of oil and natural gas properties and the drilling and exploitation of those properties.

The following table is a summary of the proved reserves and production of our oil and natural gas properties as of June 30, 2007.

Field	As of June 30, 2007(1)						1st Half 2007 Average Daily Production	Reserve-to- Production Ratio(3)	Estimated Production Decline Rate(4)
	Estimated Proved Reserves	Percent of Total Proved Reserves		Percent Natural Gas(2)		Estimated Proved Developed Reserves
	(Bcfe)					(Bcfe)	(MMcfe/d)	(Years)
Texas
Waddell Ranch	42.3	29.1	%	46.1	%	33.9	5.9	19.6	10	%
Sawyer	38.3	26.3	%	99.1	%	28.9	10.6	9.9	12	%
TXL North	24.2	16.7	%	36.8	%	20.0	3.1	21.4	7	%
New Mexico
Jalmat	38.3	26.4	%	94.4	%	30.4	6.1	17.2	13	%
Oklahoma
Carpenter / Carpenter NE	2.2	1.5	%	99.7	%	2.2	0.6	10.1	12	%
Total	145.3	100.0	%	72.1	%	115.4	26.3	15.1	11	%

(1) Our natural gas and oil proved reserve information as of June 30, 2007 is based on a reserve report prepared by Netherland, Sewell & Associates, Inc., an independent engineering firm. See Appendix C.

(2) Calculated using natural gas equivalents of six Mcf of natural gas per Bbl of oil or NGL.

(3) The reserve-to-production ratio is calculated by dividing our estimated net proved reserves as of June 30, 2007 by our annualized average daily production for the six months ended June 30, 2007.

(4) Represents percentage decrease in annual production from our proved developed producing reserves in 2009 when compared to 2008 as estimated by NSAI.

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Business Strategy

Our primary business objective is to generate stable cash flows through maintaining our current production levels and asset base over the long term in a manner that will allow us to make quarterly cash distributions to our unitholders at the minimum quarterly distribution rate of $0.35 per unit and, over time, to grow our production and asset base to increase our quarterly cash distribution rate. We intend to accomplish this objective by executing the following business strategies:

Make accretive acquisitions of properties with long-lived, stable and predictable production profiles.We seek to acquire properties that possess the following characteristics:

• predictable production profiles;

• long reserve lives;

• moderate production decline rates;

• relatively low ongoing capital requirements; and

• relatively low risk reserve development and exploitation potential.

While our current properties are located primarily in the Permian Basin, we will assess acquisition opportunities in other areas with long-lived reserves and may expand into those areas if attractive opportunities become available.

In addition to acquisition of properties from third parties, we expect to have the opportunity to make future acquisitions of oil and natural gas properties directly from Petrohawk. After contribution of the partnership properties to us, Petrohawk will continue to own additional oil and natural gas properties with characteristics that are or, after additional capital is invested, may be well suited for us. Although Petrohawk is not under any obligation to sell properties to us, we believe Petrohawk will have a strong incentive to do so given its significant ownership of limited and general partner interests in us. In addition, we expect to have the opportunity to participate with Petrohawk in jointly pursuing acquisitions of oil and natural gas properties that may not be attractive acquisition candidates for either of us individually or that we would not be able to pursue on our own. For example, a package of oil and natural gas properties may include both long-lived assets with low risk development and exploitation opportunities that would be of interest to us and assets with greater growth opportunities, involving deployment of relatively more capital which would be of interest to Petrohawk.

Maintain a multi-year inventory of relatively low risk drilling locations and exploitation projects. Our existing properties have a significant inventory of relatively low risk drilling locations and exploitation projects which we believe allows us to add additional reserves and offset a portion of the natural decline in our production. As of June 30, 2007, we had approximately 1,000 identified drilling locations consisting primarily of infill development wells and approximately 150 identified exploitation projects consisting primarily of workovers. We expect to drill a total of 22 gross (7.1 net) wells and complete 37 (14 net) workovers on our properties during 2007 with annual budgeted spending of $14 million, of which 13 (1.7 net) wells have been drilled and 25 (7.6 net) workovers have been completed at a cost of approximately $7 million. For the year ending December 31, 2008, we anticipate drilling a total of 47 (12.1 net) wells and completing 44 (16.4 net) workovers with budgeted spending of approximately $16 million.

Reduce the volatility in our cash flows through our commodity hedging activities.Prior to the closing of this offering, we intend to enter into hedging arrangements to reduce the impact of natural gas price volatility on our cash flows from operations. As of October 25, 2007, Petrohawk has entered into swap agreements covering 3,660,000 MMBtu of natural gas and 275 MBbls of oil for calendar years 2008, 2009 and 2010. The hedged volumes represent approximately 56% of our forecasted total production of 9,405 MMcfe for the twelve months ended December 31, 2008 at weighted average prices of $8.25 per MMBtu for natural gas and $81.17 per Bbl for oil. Petrohawk will assign those derivative contracts to us at the closing of this offering. Petrohawk anticipates

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entering into additional derivative contracts (to be assigned to us at the closing of this offering) so that approximately 80% to 85% of our estimated net production of oil and natural gas from proved developed producing reserves will be covered by derivatives through December 31, 2010. By removing a portion of price volatility associated with our future oil and natural gas production, we will mitigate, but not eliminate, the potential effects of changing oil and natural gas prices on our cash flows from operations for those periods. See “Management’s Discussion and Analysis and Financial Condition and Results of Operations — How We Evaluate Our Operations — Derivative Instruments and Hedging Activities.”

Leverage the technical and managerial expertise of Petrohawk to develop and exploit our existing assets and to grow through acquisitions. The members of our technical team have significant experience working in the Permian Basin as well as other regions. In addition, our team has experience with waterflood projects, fracturing and other reservoir stimulation projects, downspacing and horizontal drilling. We seek to maximize the value of our existing assets by developing and exploiting properties with the estimated lowest risk and the highest production and reserve growth potential. We also plan to utilize the significant acquisition experience of Petrohawk’s management to acquire assets.

Competitive Strengths

We believe the following competitive strengths will enable us to achieve our primary business objective and to execute our strategies:

• Substantial drilling and exploitation inventory.We have a substantial inventory of low risk development drilling and exploitation projects. As of June 30, 2007, we had approximately 1,000 identified drilling locations, which we believe provide us with a multi-year inventory of drilling opportunities. We will seek to maintain our inventory as we expand our operations.

• Long-lived reserves with relatively predictable production profiles. Our oil and natural gas properties are characterized by stable and predictable production profiles and long-lived reserves. Our properties generally have well-established production histories and exhibit relatively moderate production declines which make them well-suited to our objective of making regular cash distributions to our unitholders. Our estimated proved reserves to production ratio was approximately 15 years based on our annualized production for the six months ended June 30, 2007.

• Our relationship with Petrohawk. We anticipate that our relationship with Petrohawk will provide us with a number of competitive advantages, including:

• the opportunity to acquire assets directly from Petrohawk that match the profile of our target properties;

• the ability to acquire assets jointly with Petrohawk, which should provide access to additional acquisition opportunities;

• the ability to leverage Petrohawk’s technical expertise, including its technical team of engineers and geoscientists, to implement our acquisition, development and exploitation strategy; and

• access to the substantial acquisition, integration, operational and risk management experience of Petrohawk’s management team.

• Our management team has significant acquisition, integration, and operational experience. Petrohawk’s experienced management, operating and technical teams have an established track record of successfully acquiring, developing, exploiting and operating oil and natural gas properties. The members of Petrohawk’s management team has experience in the oil and natural gas industry, including significant experience in the Permian Basin and other regions with properties characterized by stable and predictable production profiles and long-lived reserves. Since current management joined Petrohawk in 2004, Petrohawk has acquired and successfully integrated over 1 Tcfe of oil and natural gas reserves.

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Our Properties

Our properties are located primarily in the Permian Basin, which is one of the largest and most prolific oil and natural gas producing basins in the United States. The Permian Basin extends over 100,000 square miles in West Texas and southeastern New Mexico and has produced over 26 billion Bbls of oil and 85 Tcf of natural gas since its discovery in 1921. The Permian Basin is characterized by oil and natural gas fields with large accumulations of original hydrocarbons in place, long production histories and multiple producing formations. Because of these inherent qualities, we believe properties in this region are well suited for our partnership and its business objectives.

Our producing properties in the Permian Basin are mature fields with relatively predictable production and with relatively low production declines. We intend to pursue relatively low risk development drilling and workover projects designed to partially offset our natural production decline rates in our existing fields. We expect to drill a total of 22 gross (7.1 net) wells and complete 37 (14 net) workovers on our properties during 2007 with annual budgeted spending of $14 million, of which 13 wells (1.7 net) have been drilled and 25 (7.6 net) workovers have been completed at a cost of approximately $7 million (net) as of June 30, 2007. For the year ending December 31, 2008, we anticipate drilling a total of 47 (12.1 net) wells and completing 44 (16.4 net) workovers with budgeted spending of approximately $16 million (net).

Texas Properties

Our Texas properties are located in the Waddell Ranch field in Crane County, the Sawyer field in Sutton County, and the TXL North field in Ector County.

Waddell Ranch Field. The Waddell Ranch field complex is located in Crane County, Texas and is comprised of approximately 76,900 gross (17,000 net) acres and is productive from over 15 different reservoirs. We have 990 producing wells and 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. During 2007, we anticipate drilling 15 wells and completing 25 workovers. In 2008, we plan to drill 28 wells and complete 30 workovers at a total cost (net to our interests) of approximately $3.4 million. Through June 30, 2007, we had drilled 12 wells and completed 19 workovers. The Waddell Ranch field represented approximately 42.3 Bcfe (46% natural gas) of our estimated net proved reserves as of June 30, 2007 and 5.9 MMcfe/d of our average net production through that date. This field is operated by ConocoPhillips. Our interest in the Waddell Ranch field is derived predominantly from ownership of a partial mineral fee interest, varying in percentage from tract to tract, that is burdened by net profits interests (NPI) reserved by the prior mineral fee owners in two trusts. Through two agreements, the larger trust interest (72% of total) burdens both oil and gas with a 50% NPI and the other trust interest (28% of total) burdens the oil with a 70% NPI and the gas with a 100% NPI. Under the NPI agreements, we are allowed to recoup capital expenditures and operating expenses, including taxes, from our revenue stream prior to disbursement of the net profits interest share. We have a 9.9% working interest and a 9.7% net revenue interest on average.

Sawyer Field. This field consists of 480 producing wells and is located in Sutton County, Texas and is our second most significant property in the region. The field encompasses approximately 25,300 gross (24,500 net) acres. During the past several years our drilling programs have targeted the Canyon sandstone formations at approximately 8,000 feet. We plan to drill 7 wells and complete 1 net workover in 2008. The Sawyer field represents 38.3 Bcfe (99% natural gas) of our estimated net proved reserves as of June 30, 2007 and 10.6 MMcfe/d of our average net production through that date. This field is primarily operated by Petrohawk. We have a 94.8% average working interest and a 77.5% net revenue interest in approximately 400 operated wells and a 10.4% ORRI in approximately 80 non-operated wells.

TXL North Field. This waterflood field located in Ector County, Texas comprises 8,600 gross (1,717 net) acres, 260 producing wells and is unitized in the Clearfork/Tubb formation at approximately 5,600 feet. The operator, Apache Corporation, has focused on an active workover program in 2007 and 12 wells are planned for

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2008. This field represented 24.2 Bcfe (37% natural gas) of our estimated net proved reserves as of June 30, 2007 and 3.1 MMcfe/d of our average net production through that date. We have a 20% working interest and a 25% net revenue interest in this non-operated property.

New Mexico Property

Jalmat Field.We have 140 producing wells in the Jalmat field, located in Lea County, New Mexico encompassing 9,401 gross (8,876 net) acres. We have identified over 45 recompletion/stimulation workovers in the Tansill, Yates, Seven Rivers, Langlie Mattix and Queen formations ranging in depths from 2,700 to 4,000 feet. For 2008, 13 (12.4 net) workovers are projected at a cost of $5 million. The Jalmat field represents 38.3 Bcfe (94% natural gas) of our estimated net proved reserves as of June 30, 2007 and 6.1 MMcfe/d of our average net production through that date. The field is operated by Petrohawk. We own a 96% working interest and 79% net revenue interest in this field on average.

Oklahoma Properties

Our Oklahoma properties (comprised of the Carpenter and Carpenter NE fields) represented 2.2 Bcfe (99.7% natural gas) of our estimated net proved reserves as of June 30, 2007 and 0.6 MMcfe/d of our average net production through that date.

Carpenter Field.The Carpenter field consists of 49 producing wells and straddles Roger Mills and Beckham Counties, Oklahoma. The field covers 6,400 gross (1,812 net) acres and produces primarily from the Red Fork, Cherokee, Atoka and Morrow formations which range in depth from 13,000 to 18,000 feet. Apache, ConocoPhillips and Chesapeake are the primary operators and on average we have a 10.3% working interest and a 7.9% net revenue interest in 29 wells plus a 2.1% ORRI in an additional 20 wells in this field.

Carpenter NE Field. The Carpenter NE field consists of 12 producing wells and is located in Custer County, Oklahoma. The field covers 640 gross (32 net) acres and produces primarily from the Red Fork formation at a depth of 13,000 feet. Chesapeake is the primary operator and on average we have a 4.9% working interest and a 4.2% net revenue interest in one well plus a 0.1% ORRI in an additional 11 wells in this field.

Our Relationship with Petrohawk

One of our principal strengths is our relationship with Petrohawk (NYSE: HK), a publicly traded independent oil and natural gas company. Petrohawk is engaged in the acquisition and development of oil and natural gas reserves from onshore fields in the United States and seeks to acquire a balanced, geographically diverse portfolio of long-lived, lower risk reserves along with shorter lived, higher margin reserves. As of December 31, 2006, and including the interests to be conveyed to us, Petrohawk’s total estimated proved reserves were 1,076 Bcfe, consisting of 24 MMBbls of oil and condensate and 930 Bcf of natural gas and NGLs located primarily in the Mid-Continent region (including 204 Bcfe in the Gulf Coast region that Petrohawk has signed a definitive agreement to divest). Upon completion of this offering, Petrohawk will have a significant interest in us through its ownership of 5,904,048 common units and 5,189,742 subordinated units, representing a 53.4% limited partner interest in us, a 2% general partner interest in us and all of our incentive distribution rights.

A principal component of our business strategy is to grow our proved reserves and production through the acquisition of oil and natural gas properties characterized by long-lived, stable and predictable production profiles and that have substantial opportunities for further development and exploitation. We intend to leverage the significant experience of Petrohawk’s management team to execute our growth strategy. Petrohawk has an established track record of successfully acquiring, developing, exploiting and operating oil and natural gas properties. Subsequent to the arrival of Petrohawk’s current management in May 2004, Petrohawk has increased its proved reserves from approximately 219 Bcfe as of December 31, 2004 to approximately 1,076 Bcfe as of December 31, 2006, and has increased its average daily production from approximately 29 MMcfe/d in the three

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months ended December 31, 2004 to approximately 321 MMcfe/d for the six month period ended June 30, 2007, primarily through strategic acquisitions of oil and natural gas properties and the drilling and exploitation of those properties. After the contribution of the partnership properties to us, Petrohawk will continue to own and operate properties with estimated net proved reserves as of December 31, 2006 of 927 Bcfe (including 204 Bcfe in the Gulf Coast region that Petrohawk has signed a definitive agreement to divest), which include some properties with characteristics that are or, after additional capital is invested, may be well suited for our partnership.

Petrohawk views us as an integral part of its growth strategy. It may be in Petrohawk’s best interest to sell additional assets to us in the future. Nonetheless, no assurance can be provided as to which, if any, assets may be made available to us by Petrohawk as Petrohawk is not obligated to offer us assets for acquisition, or if we will choose to pursue the opportunity to acquire such assets if they are made available to us. Furthermore, Petrohawk evaluates acquisitions and divestitures and may elect to acquire or divest oil and natural gas properties in the future without offering us the opportunity to participate. After this offering, Petrohawk will continue to be free to act in a manner that is beneficial to its interests and may be detrimental to ours, which may include competing with us for future acquisition opportunities. Accordingly, while our relationship with Petrohawk and its subsidiaries is a significant strength, it also is a source of potential conflicts. See “Conflicts of Interest and Fiduciary Duties.”

At the closing of this offering, we will enter into an administrative services agreement with Petrohawk, HK Management and our general partner pursuant to which Petrohawk and its subsidiaries will perform administrative services for us such as accounting, business development, finance, land, legal, engineering, investor relations, management, marketing, information technology, insurance, government regulations, communications, regulatory, environmental and human resources. Petrohawk and its subsidiaries will not be liable to us for their performance of, or failure to perform, services under the administrative services agreement unless their acts or omissions constitute gross negligence or willful misconduct. Petrohawk and its subsidiaries will be reimbursed for their costs incurred in providing such services to us, including for salary, bonus, incentive compensation and other amounts paid by Petrohawk and its subsidiaries to persons who perform services for us or on our behalf. Our general partner is entitled to determine in good faith the expenses that are allocable to us. Petrohawk has informed us that it intends initially to structure the reimbursement of these costs in the form of a monthly billing of a portion of Petrohawk’s corporate and other expenses, representing an estimated allocable share of time spent by the officers and employees of Petrohawk and its subsidiaries on our operations. We expect that the annual reimbursement charge will be approximately $2.9 million and will be pro-rated for the initial period from the closing of this offering through December 31, 2008. Petrohawk has indicated that it expects that it will review at least annually with the board of directors of HK Management this reimbursement arrangement and any changes to the amount or methodology by which it is determined. In addition, we will incur additional third party expenses, such as those incurred as a result of our being a publicly traded partnership, which we expect to approximate $2.8 million annually. See “Certain Relationships and Related Transactions.”

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Oil and Natural Gas Data

Oil and Natural Gas Reserves

The following table sets forth our estimated net proved reserves for the dates indicated. Our reserve estimates as of December 31, 2006 and June 30, 2007 are based on reserve reports prepared by NSAI, our independent petroleum engineers. Estimated proved reserves as of each date indicated reflect all acquisitions and dispositions completed as of that date. The reserve estimates were based upon the engineer’s review of production histories and other geological, economic, ownership and engineering data.

	December 31, 2006(1)		June 30, 2007(1)
Reserve Data:
Estimated net proved reserves:
Oil (MMBbls)	6.8		6.8
Natural gas (Bcf) (2)	107.7		104.7
Total (Bcfe)	148.6		145.3
Proved developed (Bcfe)	119.6		115.4
Proved undeveloped (Bcfe)	29.0		29.9
Proved developed reserves as % of total estimated net proved reserves	80	%	79	%
% Natural gas (2)	72	%	72	%

(1) Our estimates of proved reserves have been made in accordance with SEC guidelines using constant oil and natural gas prices and operating costs at the date indicated and are based on the December 31, 2006 West Texas Intermediate posted price of $57.75 per barrel of oil and Henry Hub spot market price of $5.63 per MMBtu of gas and the June 30, 2007 West Texas Intermediate posted price of $67.25 per barrel of oil and Henry Hub spot market price of $6.80 per MMBtu of gas.

(2) Includes NGL volumes calculated using natural gas equivalents of six Mcf of natural gas per Bbl of NGL.

As of June 30, 2007, our estimated net proved reserves totaled 145.3 Bcfe (79% proved developed), comprised of 6,766 MBbls of oil (28% of the total) and 104.7 Bcf of natural gas, and had an estimated proved reserves to production ratio of 15 years. See “Glossary of Terms” for an explanation of the terms “estimated proved reserves,” “proved developed reserves,” “proved undeveloped reserves” and related terms. You should not place undue reliance on estimates of proved reserves. See “Risk Factors — Risks Related to Our Business — The estimated oil and natural gas reserve quantities and future production rates set forth in this prospectus are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or the underlying assumptions will materially affect the quantities and present value of our reserves.”

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Production, Prices and Costs

The following table sets forth certain information regarding our net production volumes, average sales prices realized and certain expenses associated with sales of oil and natural gas for the periods indicated. We urge you to read this information in conjunction with the information contained in our financial statements and related notes included elsewhere in this prospectus. The information set forth below is not necessarily indicative of future results.

	Year Ended December 31, 2006			Six Months Ended June 30, 2007
	HK Energy Partners LP		HK Energy Partners LP	HK Energy Partners LP
	Predecessor		(Pro Forma)(1)	(Pro Forma)(1)
Production:
Oil (MBbl)		356	361		171
Natural gas (MMcf)(2)		5,646	7,951		3,746
Total production (MMcfe)		7,780	10,116		4,772
Average daily production (MMcfe/d)		21.3	27.7		26.3
Averageprice per unit (excluding hedges):
Oil (per Bbl)	$	58.95	$59.03	$	54.88
Gas (per Mcf)		6.72	7.08		7.38
Averagecost per Mcfe:
Lease operating expenses	$	1.12	$  1.02	$	1.16
Other operating expenses(3)		0.14	0.17		0.18
Taxes other than income		0.72	0.74		0.77

(1) The unaudited pro forma combined statements of operations gives effect to the formation of the partnership, the contribution to the partnership by affiliates of Petrohawk of all of the partnership properties, and certain other transactions as if they had occurred on January 1, 2006.

(2) Includes NGL volumes calculated using natural gas equivalents of six Mcf of natural gas per Bbl of NGL.

(3) Includes workover and gathering, transportation and other expenses.

Developed Acreage

The following table summarizes the estimated developed leasehold acreage of the partnership properties as of December 31, 2006. We have excluded acreage in which our interest is limited to a royalty or overriding royalty interest. The partnership properties do not include any material undeveloped leasehold acreage.

	Developed
Field	Gross	Net
Texas
Waddell Ranch	76,922	17,004
Sawyer	25,316	24,505
TXL North	8,560	1,717
Total Texas	110,798	43,226
New Mexico
Jalmat	9,401	8,876
Oklahoma
Carpenter / Carpenter NE	7,040	1,844
Total	127,239	53,946

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Drilling Activity

The following table sets forth information with respect to development and exploration wells we completed from January 1, 2004 through June 30, 2007. The number of gross wells is the total number of wells we participated in, regardless of our ownership interest in the wells. The number of net wells is the sum of fractional working interests we own in our gross wells expressed as whole numbers and fractions thereof. A producing well is a well found to be capable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well. A dry well is not a producing well.

	June 30,		Years Ended December 31,
	2007		2006		2005		2004
	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Exploratory Wells:
Productive	9.0	1.3	11.0	1.3	—	—	—	—
Dry	—	—	—	—	—	—	—	—
Total Exploratory	9.0	1.3	11.0	1.3	—	—	—	—
Development Wells:
Productive	4.0	0.4	33.0	11.4	21.0	5.8	48.0	9.7
Dry	—	—	—	—	—	—	1.0	—
Total Development	4.0	0.4	33.0	11.4	21.0	5.8	49.0	9.7
Total Wells:
Productive	13.0	1.7	44.0	12.7	21.0	5.8	48.0	9.7
Dry	—	—	—	—	—	—	1.0	—
Total	13.0	1.7	44.0	12.7	21.0	5.8	49.0	9.7

The information above should not be considered indicative of future drilling performance, nor should it be assumed that there is any correlation between the number of productive wells drilled and the amount of oil and natural gas that may ultimately be recovered. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Well Operations

We will enter into an operating agreement with Petrohawk Operating Company, a subsidiary of Petrohawk. Under this operating agreement, Petrohawk Operating Company will act as operator of the oil and natural gas wells in which we own an interest if our interest entitles us to control the appointment of the operator of the well. As operator, Petrohawk Operating Company will design and manage the drilling and completion of a well, and will manage the day-to-day operating and maintenance activities for our wells.

Under the operating agreement, Petrohawk Operating Company will establish a joint account for each well in which we have an interest. We will be required to pay our working interest share of amounts charged to the joint account. The joint account will be charged with all direct expenses incurred in the operation of our wells. The determination of which direct expenses can be charged to the joint account and the manner of charging direct expenses to the joint account for our wells will be done in accordance with the Council of Petroleum Accountants Societies, or COPAS, model form of accounting procedure.

Under the COPAS model form, direct expenses include the costs of third party services performed on our properties and well and other equipment used on our properties. In addition, direct expenses will include the allocable share of the cost of the Petrohawk employees who perform services on our properties. The allocation of the cost of Petrohawk employees who perform services on our properties will be based on a time study to be completed by Petrohawk at least annually.

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During 2006, pro forma lease operating expenses were $10.3 million. Of that amount, $4.2 million represented reimbursement of third party costs incurred by Petrohawk, and $7.8 million was payment to Petrohawk for the costs of its lease expenses employees and facilities. During the six months ended June 30, 2007, pro forma lease operating expenses were $5.5 million.

Oil and Natural Gas Leases

The typical oil and natural gas lease agreement provides for the payment of royalties to the mineral owner for all oil and natural gas produced from any well(s) drilled on the lease premises. In the Permian Basin, this amount has typically been between 12.5% and 20% for oil and natural gas, resulting in between an 80% and 87.5% net oil and natural gas revenue interest to us for most leases directly acquired by us.

Substantially all of our oil and natural gas leases are held by production, which means that for as long as our wells continue to produce oil or gas, we will continue to own the lease.

Hedging Activity

We enter into hedging transactions with unaffiliated third parties with respect to natural gas prices and interest rates to achieve more predictable cash flows and to reduce our exposure to short-term fluctuations in natural gas prices and interest rates. For a more detailed discussion of our hedging activities, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — How We Evaluate Our Operations — Derivative Instruments and Hedging Activities.”

Competition

The oil and natural gas industry is highly competitive. We encounter strong competition from other independent operators and from major oil companies in acquiring properties, contracting for development equipment and securing trained personnel. Many of these competitors have financial and technical resources and staffs substantially larger than ours. As a result, our competitors may be able to pay more for desirable leases, or to evaluate, bid for and purchase a greater number of properties or prospects than our financial or personnel resources will permit.

We are also affected by competition for rigs and the availability of related equipment. In the past, the oil and natural gas industry has experienced shortages of development rigs, equipment, pipe and personnel, which has delayed development drilling and other exploitation activities and has caused significant price increases. We are unable to predict when, or if, such shortages may occur or how they would affect our development and exploitation program.

Competition is also strong for attractive oil and natural gas producing properties, undeveloped leases and development rights, and we cannot assure you that we will be able to compete satisfactorily when attempting to make further acquisitions.

Title to Properties

As is customary in the oil and natural gas industry, we initially conduct only a cursory review of the title to our properties on which we do not have proved reserves. Prior to the commencement of development operations on those properties, we conduct a thorough title examination and perform curative work with respect to significant defects. To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing any title defects at our expense. We generally will not commence

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development operations on a property until we have cured any material title defects on such property. Prior to completing an acquisition of producing oil leases, we perform title reviews on the most significant leases and, depending on the materiality of properties, we may obtain a title opinion or review previously obtained title opinions. As a result, we believe that we have satisfactory title to our producing properties in accordance with standards generally accepted in the oil and natural gas industry. Our oil properties are subject to customary royalty and other interests, liens for current taxes and other burdens which we believe do not materially interfere with the use of or affect our carrying value of the properties.

Some of our oil and natural gas leases, easements, rights-of-way, permits, licenses and franchise ordinances require the consent of the current landowner to transfer these rights, which in some instances is a governmental entity. We believe that we have obtained or will obtain sufficient third-party consents, permits and authorizations for the transfer of the assets necessary for us to operate our business in all material respects as described in this prospectus. Record title to some of our assets will continue to be held by our affiliates until we have made the appropriate filings in the jurisdictions in which such assets are located and obtained any consents and approvals that are not obtained prior to transfer. With respect to any consents, permits or authorizations that have not been obtained, we believe that these consents, permits or authorizations generally will be obtained after the closing of this offering, or that the failure to obtain these consents, permits or authorizations will have no material adverse effect on the operation of our business.

Seasonal Nature of Business

Seasonal weather conditions and lease stipulations can limit our development activities and other operations and, as a result, we seek to perform the majority of our development during the summer months. These seasonal anomalies can pose challenges for meeting our well development objectives and increase competition for equipment, supplies and personnel during the spring and summer months, which could lead to shortages and increase costs or delay our operations.

Environmental Matters and Regulation

General

Our operations are subject to stringent and complex federal, state and local laws and regulations governing environmental protection, including air emissions, water quality, wastewater discharges and solid waste management. These laws and regulations may, among other things:

• require the acquisition of various permits before development commences;

• require the installation of expensive pollution control equipment;

• enjoin some or all of the operations of facilities deemed in non-compliance with permits;

• restrict the types, quantities and concentration of various substances that can be released into the environment in connection with oil and natural gas development and production activities;

• restrict the way in which wastes are handled and disposed;

• limit or prohibit development activities on certain lands lying within wilderness, wetlands, areas inhabited by threatened or endangered species and other protected areas; and

• require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells.

These laws, rules and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, Congress and federal and state agencies frequently revise environmental laws and regulations, and the clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. Any changes that result in

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indirect compliance costs or additional operating restrictions, including costly waste handling, disposal and cleanup requirements for the oil and natural gas industry could have a significant impact on our operating costs.

The following is a discussion of some of the existing environmental, operational safety and other laws and regulations that relate to our operations.

Waste Handling

The Resource Conservation and Recovery Act, or RCRA, and comparable state statutes, regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous solid wastes. Under the auspices of the federal Environmental Protection Agency, or EPA, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters and most of the other wastes associated with the exploration, development and production of crude oil or natural gas are currently regulated under RCRA’s non-hazardous waste provisions. However, it is possible that certain oil and natural gas exploration and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. Any such change could result in an increase in our costs to manage and dispose of wastes, which could have a material adverse effect on our results of operations and financial condition. Also, in the course of our operations, we generate some amounts of ordinary industrial wastes, such as paint wastes, waste solvents and waste oils, that may be regulated as hazardous wastes.

Site Remediation

The Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, also known as the Superfund law, imposes joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include the current and past owner or operator of the site where the release occurred, and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA authorizes the EPA, and in some cases third parties, to take actions in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.

We currently own, lease or operate numerous properties that have been used for oil and natural gas exploration and production for many years. Although we believe that we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes or hydrocarbons may have been released on or under the properties owned or leased by us, or on or under other locations, including off-site locations, where such substances have been taken for disposal. In addition, some of our properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes or hydrocarbons was not under our control. In fact, there is evidence that petroleum spills or releases have occurred in the past at some of the properties owned or leased by us. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to remove previously disposed substances and wastes, remediate contaminated property or perform remedial plugging or pit closure operations to prevent future contamination.

Water Discharges

The Clean Water Act, or CWA, and analogous state laws, impose strict controls on the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by EPA or an analogous state agency. The CWA regulates storm water run-off from oil and natural gas facilities and

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requires a storm water discharge permit for certain activities. Such a permit requires the regulated facility to monitor and sample storm water run-off from its operations. The CWA and regulations implemented thereunder also prohibit discharges of dredged and fill material in wetlands and other waters of the United States unless authorized by an appropriately issued permit. Spill prevention, control and countermeasure requirements of the CWA require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the CWA and analogous state laws and regulations.

Air Emissions

The federal Clean Air Act, or CAA, and comparable state laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including oil and natural gas exploration and production facilities, and also impose various monitoring and reporting requirements. Such laws and regulations may require a facility to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in the increase of existing air emissions, obtain and strictly comply with air permits containing various emissions and operational limitations or utilize specific emission control technologies to limit emissions.

Permits and related compliance obligations under the CAA, as well as changes to state implementation plans for controlling air emissions in regional non-attainment areas, may require oil and natural gas exploration and production operations to incur future capital expenditures in connection with the addition or modification of existing air emission control equipment and strategies. In addition, some oil and natural gas facilities may be included within the categories of hazardous air pollutant sources, which are subject to increasing regulation under the CAA. Failure to comply with these requirements could subject a regulated entity to monetary penalties, injunctions, conditions or restrictions on operations and enforcement actions. Oil and natural gas exploration and production facilities may be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions.

The U.S. Congress is currently considering proposed legislation directed at reducing “greenhouse gas emissions.” Certain states have already adopted legislation, regulations and/or initiatives addressing greenhouse gas emissions from various sources, primarily power plants. Additionally, on April 2, 2007, the U.S. Supreme Court ruled inMassachusetts v. EPA that the EPA has authority under the CAA to regulate greenhouse gas emissions from mobile sources (e.g., cars and trucks). The Court also held that greenhouse gases fall within the CAA’s definition of “air pollutant,” which could result in future regulation of greenhouse gas emissions from stationary sources, including those used in oil and natural gas exploration and production operations. It is not possible at this time to predict how legislation that may be enacted to address greenhouse gas emissions would impact the oil and natural gas exploration and production business. However, future laws and regulations could result in increased compliance costs or additional operating restrictions and could have a material adverse effect on our business, financial condition, demand for our operations, results of operations and cash flows.

Activities on Federal Lands

Oil and natural gas exploration and production activities on federal lands are subject to the National Environmental Policy Act, or NEPA. NEPA requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. Exploration and production activities on federal lands require governmental permits that are subject to the requirements of NEPA. This process has the potential to delay the development of oil and natural gas projects.

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Occupational Safety and Health Act

We are subject to the requirements of the federal Occupational Safety and Health Act, or OSH Act, and comparable state statutes. These laws and the implementing regulations strictly govern the protection of the health and safety of employees. The Occupational Safety and Health Administration’s hazard communication standard, EPA community right-to-know regulations under Title III of CERCLA and similar state statutes require that we organize and/or disclose information about hazardous materials used or produced in our operations. We believe that we are in substantial compliance with these applicable requirements and with other OSH Act and comparable requirements.

We believe that we are in substantial compliance with all existing environmental laws and regulations applicable to our current operations and that our continued compliance with existing requirements will not have a material adverse impact on our financial condition and results of operations. For instance, we did not incur any material capital expenditures for remediation or pollution control activities for the year ended December 31, 2006. Additionally, as of the date of this prospectus, we are not aware of any environmental issues or claims that will require material capital expenditures during 2007. However, accidental spills or releases may occur in the course of our operations, and we cannot assure you that we will not incur substantial costs and liabilities as a result of such spills or releases, including those relating to claims for damage to property and persons. Moreover, we cannot assure you that the passage of more stringent laws or regulations in the future will not have a negative impact on our business, financial condition, results of operations or ability to make distributions to you.

Other Regulation of the Oil and Natural Gas Industry

The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. 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 rules and regulations binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.

Legislation continues to be introduced in Congress and development of regulations continues in the Department of Homeland Security and other agencies concerning the security of industrial facilities, including oil and natural gas facilities. Our operations may be subject to such laws and regulations. Presently, it is not possible to accurately estimate the costs we could incur to comply with any such facility security laws or regulations, but such expenditures could be substantial.

Development and Production

Our operations are subject to various types of regulation at the federal, state and local levels. These authorities require, among other things, permits for the development of wells, development bonds and reports concerning operations. Most states and some counties and municipalities in which we operate also regulate one or more of the following:

• the location of wells;

• the method of developing and casing wells;

• the surface use and restoration of properties upon which wells are drilled;

• the plugging and abandoning of wells; and

• notice to surface owners and other third parties.

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State laws and regulations control the size and shape of development and spacing units or proration units governing the pooling of natural gas and oil properties. Some states allow forced pooling or integration of tracts to facilitate exploitation while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from natural gas and oil wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of natural gas and oil we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes production, ad valorem and other taxes with respect to the production and sale of oil, natural gas and NGLs within its jurisdiction.

Federal Regulation

The price at which we buy and sell natural gas currently is not subject to federal regulation and, for the most part, is not subject to state regulation. In the past, the federal government has regulated the prices at which produced oil and gas could be sold. Currently, “first sales” of natural gas by producers and marketers, and all sales of crude oil, condensate and NGLs, can be made at uncontrolled market prices, but Congress could reenact price controls at any time.

Our sales of natural gas are affected by the availability, terms and cost of pipeline transportation. The rates and terms and conditions of pipeline transportation service are subject to extensive federal and/or state regulation. The rates charged by interstate pipelines subject to the FERC’s jurisdiction may be subject to change pursuant to pipeline request, FERC or third-party complaint or by rulemaking. Rate changes, alterations of rate zones, new natural gas quality specifications, and other changes to pipeline service and operation could affect, directly or indirectly, the marketability of our gas or the prices we receive for our production. The FERC is continually proposing and implementing new rules and regulations affecting those segments of the natural gas industry. These initiatives also may affect the intrastate transportation of natural gas under certain circumstances. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry, and these initiatives often reflect more light handed regulation. However, some regulations may impose costly or burdensome obligations on pipelines downstream from our production, which could adversely affect our operations either directly or indirectly. We cannot predict the ultimate impact of these regulatory changes to our natural gas production and marketing operations, and we note that some of the FERC’s more recent proposals may adversely affect the availability and reliability of interruptible transportation service on interstate pipelines. We do not believe that we will be affected by any such FERC action materially differently than other natural gas marketers with which we compete.

With regard to our physical purchases and sales of energy commodities, and any related hedging activities that we undertake, we are required to observe anti-market manipulation laws and related regulations enforced by the FERC and/or the Commodity Futures Trading Commission, or the CFTC. The Energy Policy Act of 2005, or EPAct 2005, gave the FERC increased oversight of wholesale electricity and natural gas markets, as well as enforcement authority to investigate and penalize manipulation of these energy markets. EPAct 2005 amended the NGA to prohibit market manipulation and also amended the NGA, and the Natural Gas Policy Act of 1978, or NGPA, to increase civil and criminal penalties for any violations of the NGA, NGPA and any rules, regulations or orders of the FERC to up to $1,000,000 per day, per violation. FERC’s current market manipulation rules make it unlawful for any entity, in connection with the purchase or sale of natural gas or transportation service subject to the FERC’s jurisdiction, to defraud, make an untrue statement or omit a material fact or engage in any practice, act or course of business that operates or would operate as a fraud or deceit upon any entity. This final rule works together with the FERC’s enhanced penalty authority to provide increased oversight of the natural gas marketplace. The FERC has also announced its intention to promulgate additional regulations intended to increase the transparency of wholesale energy markets, protect the integrity of such markets, and improve its ability to assess market forces and detect market manipulation.

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The CFTC holds authority to investigate and enforce the Commodity Exchange Act, or CEA, which among other things prohibits attempted or actual manipulation of the price of any commodity in interstate commerce. The CFTC holds the position that it may police both the physical and futures commodity markets for intentional conduct resulting in commodity prices which do not reflect basic forces of supply and demand. The FERC and CFTC hold substantial enforcement authority and have acted aggressively over recent years to investigate and prosecute market irregularities. These agencies operate under anti-market manipulation laws and regulations that are broadly worded and that arguably grant overlapping regulatory jurisdiction. If we violate applicable anti-market manipulation laws and regulations, we could also be subject to related third party damage claims by, among others, sellers, royalty owners and taxing authorities.

State Regulation

The various states regulate the development, production, gathering and sale of oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. Texas currently imposes a natural gas production tax of 7.5% of the market value of the natural gas. Texas also imposes an oil production tax at the greater of 4.6% of the market value of the oil produced or 4.6¢ per Bbl. In addition, producers of crude petroleum in Texas pay a tax of 3/16 of one cent per Bbl produced. In addition to production taxes, Texas imposes ad valorem taxes on oil and natural gas properties and production equipment.

New Mexico currently imposes a tax on natural gas processing, an oil and gas production equipment ad valorem tax, and four taxes on the production of oil and gas. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and natural gas resources. States may regulate rates of production and may establish maximum daily production allowables from oil and natural gas wells based on market demand or resource conservation, or both. The effect of these regulations may be to limit the amounts of oil and natural gas that may be produced from our wells, and to limit the number of wells or locations we can drill. States do not regulate wellhead prices or engage in other similar direct economic regulation of production, but there can be no assurance that they will not do so in the future.

Employees

Immediately following the closing of this offering, HK Management, the general partner of our general partner, will have six executive officers who willspend a portion of their time onour operations. HK Management will not have any full time employees upon consummation of the offering but may hire full-time employees after closing of the offering. At December 31, 2006, Petrohawk, the sole member of HK Management, had approximately 318 full-time employees. To carry out our operations, Petrohawk employs the people who will provide direct support to our operations. None of these employees are covered by collective bargaining agreements. Petrohawk considers its relationships with its employees to be good. For more information about the management of our partnership and our use of Petrohawk personnel, see “Management.” For more information on the administrative services agreement, please read “Certain Relationships and Related Transactions — Administrative Services Agreement.”

Offices

Petrohawk’s principal executive offices are located at 1000 Louisiana, Suite 5810, Houston, Texas 77002, which is also where our principal executive offices are located.

Legal Proceedings

Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, we are not currently a party to any material legal proceedings. In addition, we are not aware of any material legal or governmental proceedings against us, or contemplated to be brought against us, under the various environmental protection statutes to which we are subject.

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MANAGEMENT

Management of HK Energy Partners LP

Because our general partner is a limited partnership, its general partner, HK Management, will manage our operations and activities. Our general partner is not elected by our unitholders and will not be subject to re-election on a regular basis in the future. Unitholders will not be entitled to elect the directors of HK Management or directly or indirectly participate in our management or operation. Our general partner owes a fiduciary duty to our unitholders. Our general partner will be liable, as general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made expressly nonrecourse to it. Our general partner therefore may cause us to incur indebtedness or other obligations that are nonrecourse to it.

The directors of HK Management will oversee our operations. Within 12 months of closing this offering, HK Management will have at least seven directors. Petrohawk will elect all members to the board of directors of HK Management and we expect that there will be at least three directors that are independent as defined under the independence standards established by The New York Stock Exchange. The New York Stock Exchange does not require a listed limited partnership like us to have a majority of independent directors on the board of directors of our general partner or to establish a nominating and governance committee.

In compliance with the requirements of The New York Stock Exchange, Petrohawk will appoint at least one independent member to the board prior to the closing of this offering. Petrohawk will appoint a second independent member within 90 days of the closing of this offering and no less than a third additional independent member within 12 months of the closing of this offering. The independent members of the board of directors of HK Management will serve as the initial members of the conflicts and audit committees of the board of directors of HK Management.

At least two independent members of the board of directors of HK Management will serve on a conflicts committee to review specific matters that the board believes may involve conflicts of interest. The conflicts committee will determine if the resolution of the conflict of interest is fair and reasonable to us. The members of the conflicts committee may not be officers, employees or security holders of our general partner or directors, officers or employees of its affiliates, and must meet the independence and experience standards established by The New York Stock Exchange and the Securities Exchange Act of 1934, as amended, to serve on an audit committee of a board of directors, and certain other requirements. Any matters approved by the conflicts committee will be conclusively deemed to be fair and reasonable to us, approved by all of our partners, and not a breach by our general partner of any duties it may owe us or our unitholders.

In addition, HK Management will have an audit committee of at least three directors who meet the independence and experience standards established by The New York Stock Exchange and the Securities Exchange Act of 1934, as amended. The audit committee will assist the board of directors in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements and corporate policies and controls. The audit committee will have the sole authority to retain and terminate our independent registered public accounting firm, approve all auditing services and related fees and the terms thereof, and pre-approve any non-audit services to be rendered by our independent registered public accounting firm. The audit committee will also be responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm will be given unrestricted access to the audit committee.

All of our executive officers will be employees of Petrohawk and will spend a portion of their time on our business and affairs. The officers of HK Management will manage the day-to-day affairs of our business. We will also utilize a significant number of other employees of Petrohawk to operate our business and provide us with general and administrative services. We will reimburse Petrohawk for allocated expenses of operational personnel who perform services for our benefit and we will reimburse Petrohawk for allocated general and administrative expenses. See “— Reimbursement of Expenses of Our General Partner.”

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Directors and Executive Officers

The following table shows information for the directors and executive officers of HK Management. Executive officers and directors are elected for one-year terms.

Name	Age	Position with HK Management
Floyd C. Wilson	60	Chairman of the Board, President and Chief Executive Officer
Stephen W. Herod	48	Executive Vice President — Corporate Development and Assistant Secretary
Mark J. Mize	35	Executive Vice President — Chief Financial Officer and Treasurer
Larry L. Helm	60	Executive Vice President — Finance and Administration
Richard K. Stoneburner	53	Executive Vice President — Chief Operating Officer
David S. Elkouri	53	Executive Vice President — General Counsel and Secretary

Directors of HK Management hold office until the earlier of their death, resignation, removal or disqualification or until their successors have been elected and qualified. Officers serve at the discretion of the board of directors. There are no family relationships among any of our directors or executive officers.

Floyd C. Wilsonbecame the Chairman of the board of directors, President and Chief Executive Officer of HK Management in October 2007. Mr. Wilson has served as Chairman of the Board, President and Chief Executive Officer of Petrohawk since May 25, 2004. Prior to joining Petrohawk, Mr. Wilson was President of PHAWK, LLC from its formation in June 2003 until May 2004. Mr. Wilson was the Chairman and Chief Executive Officer of 3TEC Energy Corporation from August 1999 until its merger with Plains Exploration & Production Company in June 2003. Mr. Wilson founded W/E Energy Company L.L.C., formerly known as 3TEC Energy Company L.L.C. in 1998 and served as its President until August 1999. Prior to his involvement with 3TEC, Mr. Wilson founded Hugoton Energy Corporation in 1987, and served as its Chairman, President and Chief Executive Officer. In 1994, Hugoton completed an initial public offering and was merged into Chesapeake Energy Corporation in 1998. Mr. Wilson began his career in the energy business in Houston, Texas in 1970 as a completion engineer. He moved to Wichita, Kansas in 1976 to start an oil and gas operating company, one of several private energy ventures that preceded the formation of Hugoton Energy Corporation.

Stephen W. Herodbecame Executive Vice President — Corporate Development and Assistant Secretary of HK Management in October 2007. Mr. Herod has served as Executive Vice President — Corporate Development and Assistant Secretary of Petrohawk since August 1, 2005. Mr. Herod served as Vice President — Corporate Development of Petrohawk from May 25, 2004 until August 1, 2005. Prior to joining Petrohawk, he was employed by PHAWK, LLC from its formation in June 2003 until May 2004. He served as Executive Vice President — Corporate Development for 3TEC Energy Corporation from December 1999 until its merger with Plains Exploration & Production Company in June 2003 and as Assistant Secretary from May 2001 until June 2003. Mr. Herod served as a director of 3TEC from July 1997 until January 2002. Mr. Herod served as the Treasurer of 3TEC from 1999 until 2001. From July 1997 to December 1999, Mr. Herod was Vice President — Corporate Development of 3TEC. Mr. Herod served as President and a director of Shore Oil Company from April 1992 until the merger of Shore with 3TEC’s predecessor in June 1997. He joined Shore’s predecessor as Controller in February 1991. Mr. Herod was employed by Conquest Exploration Company from 1984 until 1991 in various financial management positions, including Operations Accounting Manager. From 1981 to 1984, The Superior Oil Company employed Mr. Herod as a financial analyst.

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Mark J. Mizebecame Executive Vice President — Chief Financial Officer and Treasurer of HK Management in October 2007. Mr. Mize has served as Executive Vice President — Chief Financial Officer and Treasurer of Petrohawk since August 1, 2007. He served as Vice President, Chief Accounting Officer and Controller from July 2005 until September 1, 2007. Mr. Mize joined Petrohawk on November 29, 2004 as Controller. Prior to joining Petrohawk, he was the Manager of Financial Reporting of Cabot Oil & Gas Corporation from January 2003 to November 2004. Prior to his employment at Cabot Oil & Gas Corporation, he was an Audit Manager with PricewaterhouseCoopers LLP from 1996 to 2002. He is a Certified Public Accountant.

Larry L. Helmbecame Executive Vice President — Finance and Administration of HK Management in October 2007. Mr. Helm has served as Executive Vice President — Finance and Administration of Petrohawk since August 1, 2007. He served as Executive Vice President — Chief Administrative Officer of Petrohawk from August 1, 2005 until August 1, 2007. Mr. Helm served as Vice President — Chief Administrative Officer from July 15, 2004 until August 1, 2005. Prior to serving as an executive officer, Mr. Helm served on Petrohawk’s board of directors for approximately two months. Mr. Helm was employed with Bank One Corporation from December 1989 through December 2003. Most recently Mr. Helm served as Executive Vice President of Middle Market Banking from October 2001 to December 2003. From April 1998 to August 1999, he served as Executive Vice President of the Energy and Utilities Banking Group. Prior to joining Bank One, he worked for 16 years in the banking industry primarily serving the oil and gas sector. He served as director of 3TEC Energy Corporation from 2000 to June 2003.

Richard K. Stoneburnerbecame Executive Vice President — Chief Operating Officer of HK Management in October 2007. Mr. Stoneburner has served as Executive Vice President — Chief Operating Officer of Petrohawk since September 13, 2007. He served as Vice President — Exploration of Petrohawk from August 1, 2005 until September 13, 2007 and served as Vice President — Exploration from May 25, 2004 until August 1, 2005. Prior to joining Petrohawk, he was employed by PHAWK, LLC from its formation in June 2003 until May 2004. He joined 3TEC in August 1999 and was its Vice President — Exploration from December 1999 until its merger with Plains Exploration & Production Company in June 2003. Mr. Stoneburner was employed by W/E Energy Company as District Geologist from 1998 to 1999. Prior to joining 3TEC, Mr. Stoneburner worked as a geologist for Texas Oil & Gas, The Reach Group, Weber Energy Corporation, Hugoton and, independently through his own company, Stoneburner Exploration, Inc. Mr. Stoneburner has over 25 years of experience in the energy business.

David S. Elkouri became Executive Vice President — General Counsel and Secretary of HK Management in October 2007. Mr. Elkouri has served as Executive Vice President — General Counsel and Secretary of Petrohawk since August 1, 2007. Mr. Elkouri co-founded and has been a member of the Hinkle Elkouri Law Firm L.L.C. and head of that firm’s corporate securities and mergers and acquisitions practice since 1987.

Reimbursement of Expenses of Our General Partner

Our general partner will not receive any management fee or other compensation for its management of our partnership under the administrative services agreement with Petrohawk or otherwise. Under the terms of the administrative services agreement, we will pay Petrohawk monthly for the provision of various general and administrative services for our benefit, which amount will be based upon HK Management’s good faith determination of the actual time spent by its personnel who perform services on our behalf or on other systematic and rational allocations as determined by HK Management. We will also reimburse Petrohawk for direct expenses incurred on our behalf and expenses allocated to us as a result of our becoming a public entity. The partnership agreement provides that our general partner will determine the expenses that are allocable to us. See “Certain Relationships and Related Transactions — Administrative Services Agreement.”

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Executive Compensation

Our general partner and HK Management were formed in October 2007. Accordingly, HK Management has not accrued any obligations with respect to management incentive or retirement benefits for its directors and officers for the 2006 fiscal year or any prior periods. We have not paid or accrued any amounts for executive compensation for the 2007 fiscal year. Accordingly, we are not presenting any compensation for historical periods. The compensation of the executive officers of HK Management will be set by the compensation committee of Petrohawk and ratified by the board of directors of HK Management. The officers of HK Management participate in employee benefit plans and arrangements sponsored by Petrohawk. HK Management has not entered into any employment agreements with any of its officers. We anticipate that HK Management’s board of directors will grant awards to officers and outside directors pursuant to the Long-Term Incentive Plan described below following the closing of this offering; however, the board has not yet made any determination as to the number of awards, the type of awards or when the awards would be granted.

Compensation Discussion and Analysis

General

We do not directly employ any of the persons responsible for managing our business and we do not have a compensation committee. We are managed by the general partner of our general partner, HK Management, the executive officers of which are employees of Petrohawk who will devote only a portion of their time to our business. Our reimbursement for the compensation of executive officers is governed by the administrative services agreement and will generally be based on time allocated to us and Petrohawk during a period.

Accordingly, the compensation committee of HK Management has ultimate decision-making authority with respect to the compensation, other than equity based compensation, of our named executive officers.

Compensation of Directors

Officers or employees of HK Management or its affiliates who also serve as directors will not receive additional cash compensation for their service as a director of HK Management. Each non-employee director will be reimbursed for his out-of-pocket expenses in connection with attending meetings of the board of directors or committees. Each director will be fully indemnified by us for his actions associated with being a director to the fullest extent permitted under Delaware law.

Long-Term Incentive Plan

General. HK Management intends to adopt a Long-Term Incentive Plan, or the Plan, for employees and directors of HK Management and its affiliates who perform services for us. The summary of the Plan contained herein does not purport to be complete and is qualified in its entirety by reference to the Plan. The Plan provides for the grant of restricted units, phantom units, unit options, substitute awards, performance awards and, with respect to unit options and phantom units, the grant of distribution equivalent rights, or DERs. Subject to adjustment for certain events, an aggregate of 2,100,000 common units may be delivered pursuant to awards under the Plan. Units that are cancelled, forfeited or are withheld to satisfy HK Management’s tax withholding obligations are available for delivery pursuant to other awards. The Plan will be administered by the compensation committee of HK Management’s board of directors.

Restricted Units and Phantom Units. A restricted unit is a common unit that is subject to forfeiture. Upon vesting, the grantee receives a common unit that is not subject to forfeiture. A phantom unit is a notional unit that entitles the grantee to receive a common unit upon the vesting of the phantom unit or, in the discretion of the compensation committee, cash equal to the fair market value of a common unit. The compensation committee may make grants of restricted units and phantom units under the Plan to eligible individuals containing such terms, consistent with the Plan, as the compensation committee may determine, including the period over which

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restricted units and phantom units granted will vest. The compensation committee may, in its discretion, base vesting on the grantee’s completion of a period of service or upon the achievement of specified financial objectives or other criteria. In addition, the restricted and phantom units will vest automatically upon a change of control (as defined in the Plan) of us or HK Management, subject to any contrary provisions in the award agreement.

If a grantee’s employment or membership on the board terminates for any reason, the grantee’s restricted units and phantom units will be automatically forfeited unless, and to the extent, the award agreement or the compensation committee provides otherwise. Common units to be delivered with respect to these awards may be common units acquired by HK Management in the open market, common units already owned by HK Management, common units acquired by HK Management directly from us or any other person, or any combination of the foregoing. HK Management will be entitled to reimbursement by us for the cost incurred in acquiring common units. If we issue new common units with respect to these awards, the total number of common units outstanding will increase.

Distributions made by us with respect to awards of restricted units may, in the compensation committee’s discretion, be subject to the same vesting requirements as the restricted units. The compensation committee, in its discretion, may also grant tandem DERs with respect to phantom units on such terms as it deems appropriate. DERs are rights that entitle the grantee to receive, with respect to a phantom unit, cash equal to the cash distributions made by us on a common unit.

We intend for the restricted units and phantom units granted under the Plan to serve as a means of incentive compensation for performance and not primarily as an opportunity to participate in the equity appreciation of the common units. Therefore, participants will not pay any consideration for the common units they receive with respect to these types of awards, and neither we nor our general partner will receive remuneration for the units delivered with respect to these awards.

Unit Options. The Plan also permits the grant of options covering common units. Unit options may be granted to such eligible individuals and with such terms as the compensation committee may determine, consistent with the Plan; however, a unit option must have an exercise price equal to the fair market value of a common unit on the date of grant.

Upon exercise of a unit option, HK Management will acquire common units in the open market at a price equal to the prevailing price on the principal national securities exchange upon which the common units are then traded, or directly from us or any other person, or use common units already owned by the general partner, or any combination of the foregoing. HK Management will be entitled to reimbursement by us for the difference between the cost incurred by HK Management in acquiring the common units and the proceeds received by HK Management from an optionee at the time of exercise. Thus, we will bear the cost of the unit options. If we issue new common units upon exercise of the unit options, the total number of common units outstanding will increase, and HK Management will remit the proceeds it received from the optionee upon exercise of the unit option to us. The unit option plan has been designed to furnish additional compensation to employees and directors and to align their economic interests with those of common unitholders.

Substitution Awards. The compensation committee, in its discretion, may grant substitute or replacement awards to eligible individuals who, in connection with an acquisition made by us, HK Management or an affiliate, have forfeited an equity-based award in their former employer. A substitute award that is an option may have an exercise price less than the value of a common unit on the date of grant of the award.

Performance Awards. The compensation committee, in its discretion, may grant performance awards to eligible individuals based upon the individuals’ satisfaction of pre-established performance criteria as determined by the committee.

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Termination of Long-Term Incentive Plan. HK Management’s board of directors, in its discretion, may terminate the Plan at any time with respect to the common units for which a grant has not theretofore been made. The Plan will automatically terminate on the earlier of the 10th anniversary of the dateit is initially approved by our unitholders or when common units are no longer available for delivery pursuant to awards under the Plan. HK Management’s board of directors will also have the right to alter or amend the Plan or any part of it from time to time and the compensation committee may amend any award; provided, however, that no change in any outstanding award may be made that would materially impair the rights of the participant without the consent of the affected participant. Subject to unitholder approval, if required by the rules of the principal national securities exchange upon which the common units are traded, the board of directors of HK Management may increase the number of common units that may be delivered with respect to awards under the Plan.

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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth the beneficial ownership of our units that will be issued upon the consummation of this offering and the related transactions and held by:

• each person who then will beneficially own 5% or more of the then outstanding units;

• all of the directors of HK Management;

• each named executive officer of HK Management; and

• all directors and executive officers of HK Management as a group.

Name of Beneficial Owner(1)	Common Units to be Beneficially Owned(2)	Percentage of Common Units to be Beneficially Owned		Subordinated Units to be Beneficially Owned	Percentage of Subordinated Units to be Beneficially Owned		Percentage of Total Units to be Beneficially Owned
Petrohawk Energy Corporation	5,904,048	39.0	%	5,189,742	100.0	%	54.5	%
Floyd C. Wilson	—			—
Stephen W. Herod	—			—
Mark J. Mize	—			—
Larry L. Helm	—			—
Richard K. Stoneburner	—			—
David S. Elkouri	—			—
All directors and executive officers as a group (six persons)	—			—

(1) Unless otherwise indicated, the address for the beneficial owner is 1000 Louisiana, Suite 5810, Houston, Texas 77002.

(2) Does not include common units that may be purchased in the directed unit program.

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CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

After this offering, Petrohawk and its affiliates will own 5,904,048 common units and 5,189,742 subordinated units representing an aggregate 53.4% limited partner interest in us. In addition, our general partner will own a 2% general partner interest in us and the incentive distribution rights.

Distributions and Payments to Our General Partner and its Affiliates

The following table summarizes the distributions and payments to be made by us to our general partner and its affiliates in connection with the formation, ongoing operation and any liquidation of HK Energy Partners LP. These distributions and payments were determined by and among affiliated entities and, consequently, are not the result of arm’s-length negotiations.

Formation Stage

The consideration received by our general partner and another subsidiary of Petrohawk for the contribution of the assets and liabilities to us       •     5,904,048 common units;   •     5,189,742 subordinated units;   •     the incentive distribution rights;   •     a 2% general partner interest in HK Energy Partners; and   •     distributions totaling $223,100,000 to our general partner and another subsidiary of Petrohawk from funds borrowed under our credit facility.

Operational Stage

Distributions of available cash to our general partner and its affiliates We will generally make cash distributions 98% to our unitholders pro rata, including our general partner and its affiliates, as the holders of an aggregate of 15,154,048 common units and 5,189,742 subordinated units, and 2% to our general partner. In addition, if distributions exceed the minimum quarterly distribution and other higher target distribution levels, our general partner will be entitled to increasing percentages of the distributions, up to 25% of the distributions above the highest target distribution level.

Assuming we have sufficient available cash to pay the full minimum quarterly distribution on all of our outstanding units for four quarters, our general partner and its affiliates would receive an annual distribution of approximately $0.6 million on their general partner interest and $15.5 million on their common and subordinated units.

Payments to our general partner and its affiliates We will reimburse Petrohawk and its affiliates for the payment of certain operating expenses, and we will pay them a monthly fee for the provision of various general and administrative services for our

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benefit. For further information regarding the administrative fee, please read “— Administrative Services Agreement” and “Business — Well Operations.”

Withdrawal or removal of our general partner If our general partner withdraws or is removed, its general partner interest and its incentive distribution rights will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests. See “The Partnership Agreement — Withdrawal or Removal of the General Partner.”

Liquidation Stage

Liquidation Upon our liquidation, the partners, including our general partner, will be entitled to receive liquidating distributions according to their respective capital account balances.

Agreements Governing the Transactions

We and other parties have entered into or will enter into the various documents and agreements that will effect the offering transactions, including the vesting of assets in, and the assumption of liabilities by, us and our subsidiaries, and the application of the proceeds of this offering. These agreements will not be the result of arm’s-length negotiations, and they, or any of the transactions that they provide for, may not be effected on terms at least as favorable to the parties to these agreements as they could have been obtained from unaffiliated third parties. All of the transaction expenses incurred in connection with these transactions, including the expenses associated with transferring assets into our subsidiaries, will be paid from the proceeds of this offering.

Administrative Services Agreement

At the closing of this offering, we intend to enter into an administrative services agreement with Petrohawk, HK Management and our general partner that will address the following matters:

• our obligation to pay Petrohawk for providing us general and administrative and all other services with respect to our existing business and operations; and

• our obligation to reimburse Petrohawk for any insurance coverage expenses it incurs with respect to our business and operations.

Pursuant to the administrative services agreement, Petrohawk will perform certain administrative functions for us, such as accounting, treasury, insurance administration and claims processing, risk management, health, safety and environmental, information technology, human resources, credit, payroll, internal audit, taxes and engineering and senior management oversight.

Any or all of the provisions of the administrative services agreement will be terminable by Petrohawk at its option if our general partner is removed without cause and units held by our general partner and its affiliates are not voted in favor of that removal. The administrative services agreement will also terminate in the event of a change of control of us, our general partner or the general partner of our general partner.

Contribution Agreement

Under the contribution agreement we will enter into upon the closing of this offering with our general partner and another subsidiary of Petrohawk, we will receive an assignment of indemnification rights and obligations pursuant to which subsidiaries of Petrohawk, whom we refer to as the indemnitors, will indemnify us

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for one year after the closing of this offering against certain potential environmental claims, losses and expenses associated with the operation of the partnership properties occurring before the closing date of this offering. Additionally, the indemnitors will indemnify us for losses attributable to title defects, retained assets and liabilities (including any preclosing litigation relating to contributed assets) and income taxes attributable to pre-closing operations. The indemnitors’ maximum liability for these indemnification obligations will not exceed $             million and the indemnitors will not have any obligation under this indemnification until our aggregate losses exceed $            . The indemnitors will have no indemnification obligations with respect to environmental claims made as a result of additions to or modifications of environmental laws promulgated after the closing date of this offering. We have agreed to indemnify Petrohawk and its subsidiaries against environmental liabilities related to our assets to the extent the indemnitors are not required to indemnify us. We also will indemnify Petrohawk and its subsidiaries for all losses attributable to the postclosing operations of the assets contributed to us, to the extent not subject to the indemnitors’ indemnification obligations.

As described under “Business — Well Operations,” we will enter into an operating agreement with our general partner and Petrohawk Operating Company, a subsidiary of Petrohawk. Under the operating agreement, we will indemnify Petrohawk Operating Company for all liabilities it incurs as operator of our properties, other than those directly attributable to its gross negligence and willful misconduct and Petrohawk Operating Company will indemnify us for liabilities we incur directly attributable to its gross negligence and willful misconduct.

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CONFLICTS OF INTEREST AND FIDUCIARY DUTIES

Conflicts of Interest

Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its affiliates (including Petrohawk) on the one hand, and our partnership and our limited partners, on the other hand. The directors and officers of HK Management have fiduciary duties to manage HK Management and our general partner in a manner beneficial to their owners. At the same time, our general partner has a fiduciary duty to manage our partnership in a manner beneficial to us and our unitholders.

Whenever a conflict arises between our general partner or its affiliates, on the one hand, and us or any other partner, on the other hand, our general partner will resolve that conflict. Our partnership agreement contains provisions that modify and limit our general partner’s fiduciary duties to our unitholders. Our partnership agreement also restricts the remedies available to unitholders for actions taken that, without those limitations, might constitute breaches of fiduciary duty.

Our general partner will not be in breach of its obligations under the partnership agreement or its duties to us or our unitholders if the resolution of the conflict is:

• approved by the conflicts committee in good faith, although our general partner is not obligated to seek such approval;

• approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner or any of its affiliates;

• on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or

• fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.

As required by our partnership agreement, the board of directors of HK Management will maintain a conflicts committee comprised of at least two independent directors. Our general partner may, but is not required to, seek the approval of such resolution from the conflicts committee of the board of directors of HK Management. If our general partner does not seek approval from the conflicts committee and the board of directors of HK Management determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the third and fourth bullet points above, then it will be presumed that, in making its decision, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Unless the resolution of a conflict is specifically provided for in our partnership agreement, our general partner or the conflicts committee may consider any factors it determines in good faith to consider when resolving a conflict. When our partnership agreement provides that someone act in good faith, it requires that person to believe he is acting in the best interests of the partnership.

Conflicts of interest could arise in the situations described below, among others.

Petrohawk is not limited in its ability to compete with us, which could cause conflicts of interest and limit our ability to acquire additional assets or businesses which, in turn, could adversely affect our results of operations and cash available for distribution to our unitholders.

Our partnership agreement does not prohibit Petrohawk from owning assets or engaging in businesses that compete directly or indirectly with us. For example, Petrohawk owns other oil and natural gas properties in East Texas/North Louisiana, the onshore Gulf Coast region, and in the Anadarko and Arkoma basins and other areas that will not be conveyed to us. In addition, Petrohawk may acquire, develop or dispose of oil and natural gas properties or other assets in the future, without any obligation to offer us the opportunity to purchase or develop any of those assets. Petrohawk is a large, established participant in the oil and natural gas industry, and has

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significantly greater resources and experience than we have, which may make it more difficult for us to compete with Petrohawk with respect to commercial activities as well as for acquisition candidates. As a result, competition from Petrohawk could adversely impact our results of operations and cash available for distribution.

Neither our partnership agreement nor any other agreement requires Petrohawk to pursue a business strategy that favors us or uses our assets or dictates what markets to pursue or grow. HK Management’s directors have a fiduciary duty to make these decisions in the best interests of the owners of Petrohawk, which may be contrary to our interests.

Because the officers and certain of the directors of HK Management are also officers and/or directors of Petrohawk, such officers and directors have fiduciary duties to Petrohawk that may cause them to pursue business strategies that disproportionately benefit Petrohawk or which otherwise are not in our best interests.

Our general partner is allowed to take into account the interests of parties other than us, such as Petrohawk, in resolving conflicts of interest.

Our partnership agreement contains provisions that reduce the standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include the exercise of its limited call right, its voting rights with respect to the units it owns, its registration rights and its determination whether or not to consent to any merger or consolidation of the partnership.

Petrohawk and its subsidiaries will have conflicts of interest between the manner in which they operate our properties and other properties owned or operated by them.

Petrohawk will operate all of our properties as well as some of its own properties that are not being contributed to us. Petrohawk and its subsidiaries will have conflicts of interest between the manner in which they operate our properties and other properties owned or operated by them. For example:

• We have agreed that Petrohawk’s proposed well operations will take precedence over any conflicting operations we propose. In addition, we are restricted in our ability to remove Petrohawk as the operator of the wells we own.

• Petrohawk will operate all of our wells and determine the manner in which its personnel and operational resources are utilized, and it is not prohibited from favoring other properties it operates over our properties, so long as it conducts itself in accordance with the operating standards set forth in the operating agreements.

We will not have any employees and will rely on the employees of Petrohawk and its affiliates.

All of the executive management personnel of HK Management will be employees of Petrohawk and will devote a portion of their time to our business and affairs. We will also use a significant number of employees of Petrohawk to operate our business and provide us with general and administrative services. Affiliates of our general partner and Petrohawk will also conduct businesses and activities of their own in which we will have no economic interest. If these separate activities are significantly greater than our activities, there could be material competition for the time and effort of the officers and employees who provide services to Petrohawk. Employees of Petrohawk (including the persons who are executive officers of HK Management) will devote such portion of their time as may be reasonable and necessary for the operation of our business. It is anticipated that the executive officers of HK Management will devote significantly less than a majority of their time to our business for the foreseeable future.

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Our partnership agreement limits our general partner’s fiduciary duties to holders of our units and restricts the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

Although our general partner has a fiduciary duty to manage us in a manner beneficial to us and our unitholders, the directors and officers of HK Management have a fiduciary duty to manage our general partner in a manner beneficial to its owner, Petrohawk. Our partnership agreement contains provisions that reduce the standards to which our general partner would otherwise be held by state fiduciary duty laws. For example, our partnership agreement:

• permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include:

• its limited call right;

• its rights to vote and transfer the units it owns;

• its registration rights; and

• its determination whether or not to consent to any merger or consolidation of the partnership or amendment to the partnership agreement;

• provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as it acted in good faith, meaning it believed the decision was in the best interests of our partnership;

• generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the conflicts committee of the board of directors of HK Management acting in good faith and not involving a vote of unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or must be “fair and reasonable” to us, as determined by our general partner in good faith and that, in determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us;

• provides that our general partner and the officers and directors of HK Management will not be liable for monetary damages to us, our limited partners or assignees for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the general partner or those other persons acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and

• provides that in resolving conflicts of interest, it will be presumed that in making its decision the general partner or the conflicts committee acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.

If you purchase any common units, you will agree to become bound by the provisions in the partnership agreement, including the provisions discussed above. See “ — Fiduciary Duties.”

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Except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval.

Under our partnership agreement, our general partner has full power and authority to do all things, other than those items that require unitholder approval or with respect to which our general partner has sought conflicts committee approval, on such terms as it determines to be necessary or appropriate to conduct our business including, but not limited to, the following:

• the making of any expenditures, the lending or borrowing of money, the assumption or guarantee of or other contracting for, indebtedness and other liabilities, the issuance of indebtedness, including indebtedness that is convertible into our securities, and the incurring of any other obligations;

• the purchase, sale or other acquisition or disposition of our securities, or the issuance of additional options, rights, warrants and unit appreciation rights relating to our securities;

• the mortgage, pledge, encumbrance, hypothecation or exchange of any or all of our assets;

• the negotiation, execution and performance of any contracts, conveyances or other instruments;

• the distribution of our cash;

• the selection and dismissal of employees and agents, outside attorneys, accountants, consultants and contractors and the determination of their compensation and other terms of employment or hiring;

• the maintenance of insurance for our benefit and the benefit of our partners;

• the formation of, or acquisition of an interest in, the contribution of property to, and the making of loans to, any limited or general partnerships, joint ventures, corporations, limited liability companies or other relationships;

• the control of any matters affecting our rights and obligations, including the bringing and defending of actions at law or in equity and otherwise engaging in the conduct of litigation, arbitration or mediation and the incurring of legal expense and the settlement of claims and litigation;

• the indemnification of any person against liabilities and contingencies to the extent permitted by law;

• the making of tax, regulatory and other filings or rendering of periodic or other reports to governmental or other agencies having jurisdiction over our business or assets; and

• the entering into of agreements with any of its affiliates to render services to us or to itself in the discharge of its duties as our general partner.

Our partnership agreement provides that our general partner must act in “good faith” when making decisions on our behalf, and our partnership agreement further provides that in order for a determination by our general partner to be made in “good faith,” our general partner must believe that the determination is in our best interests. See “The Partnership Agreement — Voting Rights” for information regarding matters that require unitholder approval.

Our general partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings, issuance of additional partnership securities and the creation, reduction or increase of reserves, each of which can affect the amount of cash that is distributed to our unitholders.

The amount of cash that is available for distribution to unitholders is affected by decisions of our general partner regarding such matters as:

• the manner in which our business is operated;

• amount, nature and timing of asset purchases and sales;

• cash expenditures;

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• the amount of borrowings;

• the issuance of additional units; and

• the creation, reduction or increase of reserves in any quarter.

Our partnership agreement provides that we and our subsidiaries may borrow funds from our general partner and its affiliates. Our general partner and its affiliates may not borrow funds from us, our operating company or its operating subsidiaries.

Our general partner determines which costs incurred by Petrohawk are reimbursable by us.

We will reimburse our general partner and its affiliates for costs incurred in managing and operating us, including costs incurred in rendering corporate staff and support services to us. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us on our behalf and expenses allocated to our general partner by its affiliates. Our partnership agreement provides that our general partner is entitled to determine in good faith the expenses that are allocable to us.

Our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf.

Our partnership agreement allows our general partner to determine, in good faith, any amounts to pay itself or its affiliates for any services rendered to us. Our general partner may also enter into additional contractual arrangements with any of its affiliates on our behalf. Similarly, agreements, contracts or arrangements between us and our general partner and its affiliates will not be required to be negotiated on an arms-length basis, although, in some circumstances, our general partner may determine that the conflicts committee of HK Management may make a determination on our behalf with respect to one or more of these types of situations.

Our general partner will determine, in good faith, the terms of any of these transactions entered into after the sale of the common units offered in this offering.

Our general partner and its affiliates will have no obligation to permit us to use any facilities or assets of our general partner or its affiliates, except as may be provided in contracts entered into specifically dealing with that use. There is no obligation of our general partner or its affiliates to enter into any contracts of this kind.

Our general partner intends to limit its liability regarding our obligations.

Our general partner intends to limit its liability under contractual arrangements so that the other party has recourse only to our assets and not against our general partner or its assets. The partnership agreement provides that any action taken by our general partner to limit its liability is not a breach of our general partner’s fiduciary duties, even if we could have obtained more favorable terms without the limitation on liability.

Our general partner may exercise its right to call and purchase common units if it and its affiliates own more than 80% of the common units.

Our general partner may exercise its right to call and purchase common units as provided in the partnership agreement or assign this right to one of its affiliates or to us. Our general partner is not bound by fiduciary duty restrictions in determining whether to exercise this right. As a result, a common unitholder may have his common units purchased from him at an undesirable time or price. See “The Partnership Agreement — Limited Call Right.”

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Common unitholders will have no right to enforce obligations of our general partner and its affiliates under agreements with us.

Any agreements between us, on the one hand, and our general partner and its affiliates, on the other, will not grant to the unitholders, separate and apart from us, the right to enforce the obligations of our general partner and its affiliates in our favor.

Our general partner decides whether to retain separate counsel, accountants or others to perform services for us.

The attorneys, independent accountants and others who have performed services for us regarding this offering have been retained by our general partner. Attorneys, independent accountants and others who perform services for us are selected by our general partner or the conflicts committee and may perform services for our general partner and its affiliates. We may retain separate counsel for ourselves or the holders of common units in the event of a conflict of interest between our general partner and its affiliates, on the one hand, and us or the holders of common units, on the other, depending on the nature of the conflict. We do not intend to do so in most cases.

Our general partner may elect to cause us to issue Class B units to it in connection with a resetting of the target distribution levels related to our general partner’s incentive distribution rights without the approval of the conflicts committee of HK Management or our unitholders. This may result in lower distributions to our common unitholders in certain situations.

Our general partner has the right, at a time when there are no subordinated units outstanding and it has received incentive distributions at the highest level to which it is entitled (25%) for each of the prior four consecutive fiscal quarters, to reset the initial cash target distribution levels at higher levels based on the distribution at the time of the exercise of the reset election. Following a reset election by our general partner, the minimum quarterly distribution amount will be reset to an amount equal to the average cash distribution amount per common unit for the two fiscal quarters immediately preceding the reset election (such amount is referred to as the “reset minimum quarterly distribution”) and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution amount. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion; however, it is possible that our general partner could exercise this reset election at a time when we are experiencing declines in our aggregate cash distributions or at a time when our general partner expects that we will experience declines in our aggregate cash distributions in the foreseeable future. In such situations, our general partner may be experiencing, or may expect to experience, declines in the cash distributions it receives related to its incentive distribution rights and may therefore desire to be issued our Class B units, which are entitled to specified priorities with respect to our distributions and which therefore may be more advantageous for the general partner to own in lieu of the right to receive incentive distribution payments based on target distribution levels that are less certain to be achieved in the then current business environment. As a result, a reset election may cause our common unitholders to experience dilution in the amount of cash distributions that they would have otherwise received had we not issued new Class B units to our general partner in connection with resetting the target distribution levels related to our general partner incentive distribution rights. See “How We Will Make Cash Distributions — General Partner’s Right to Reset Target Distribution Levels.”

Fiduciary Duties

Our general partner is accountable to us and our unitholders as a fiduciary. Fiduciary duties owed to unitholders by our general partner are prescribed by law and the partnership agreement. The Delaware Revised Uniform Limited Partnership Act, which we sometimes refer to in this prospectus as the Delaware Act, provides that Delaware limited partnerships may, in their partnership agreements, modify, restrict or expand the fiduciary duties otherwise owed by a general partner to limited partners and the partnership.

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Our partnership agreement contains various provisions modifying and restricting the fiduciary duties that might otherwise be owed by our general partner. We have adopted these restrictions to allow our general partner or its affiliates to engage in transactions with us that would otherwise be prohibited by state-law fiduciary duty standards and to take into account the interests of other parties in addition to our interests when resolving conflicts of interest. We believe this is appropriate and necessary because HK Management’s board of directors has fiduciary duties to manage our general partner in a manner beneficial to its owners, as well as to you. Without these modifications, the general partner’s ability to make decisions involving conflicts of interest would be restricted. The modifications to the fiduciary standards enable the general partner to take into consideration all parties involved in the proposed action, so long as the resolution is fair and reasonable to us. These modifications also enable HK Management to attract and retain experienced and capable directors. These modifications are detrimental to our common unitholders because they restrict the remedies available to unitholders for actions that, without those limitations, might constitute breaches of fiduciary duty, as described below, and permit our general partner to take into account the interests of third parties in addition to our interests when resolving conflicts of interest.

The following is a summary of the material restrictions of the fiduciary duties owed by our general partner to the limited partners:

State-law fiduciary duty standards Fiduciary duties are generally considered to include an obligation to act in good faith and with due care and loyalty. The duty of care, in the absence of a provision in a partnership agreement providing otherwise, would generally require a general partner to act for the partnership in the same manner as a prudent person would act on his own behalf. The duty of loyalty, in the absence of a provision in a partnership agreement providing otherwise, would generally prohibit a general partner of a Delaware limited partnership from taking any action or engaging in any transaction where a conflict of interest is present.

Rights and Remedies of Unitholders. The Delaware Act generally provides that a limited partner may institute legal action on behalf of the partnership to recover damages from a third party where a general partner has refused to institute the action or where an effort to cause a general partner to do so is not likely to succeed. In addition, the statutory or case law of some jurisdictions may permit a limited partner to institute legal action on behalf of himself and all other similarly situated limited partners to recover damages from a general partner for violations of its fiduciary duties to the limited partners.

Partnership agreement modified standards Our partnership agreement contains provisions that waive or consent to conduct by our general partner and its affiliates that might otherwise raise issues about compliance with fiduciary duties or applicable law. For example, our partnership agreement provides that when our general partner is acting in its capacity as our general partner, as opposed to in its individual capacity, it must act in “good faith” and will not be subject to any other standard under applicable law. In addition, when our general partner is acting in its individual capacity, as opposed to in its capacity as our general partner, it may act without any fiduciary obligation to us or the unitholders whatsoever. These standards reduce the obligations to which our general partner would otherwise be held.

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In addition to the other more specific provisions limiting the obligations of our general partner, our partnership agreement further provides that our general partner and the officers and directors of HK Management will not be liable for monetary damages to us, our limited partners or assignees for errors of judgment or for any acts or omissions unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that the general partner or its officers and directors acted in bad faith or engaged in fraud or willful misconduct.

Special provisions regarding affiliated transactions. Our partnership agreement generally provides that affiliated transactions and resolutions of conflicts of interest not involving a vote of unitholders and that are not approved by the conflicts committee of the board of directors of HK Management must be:

• on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or

• “fair and reasonable” to us, taking into account the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to us).

If our general partner does not seek approval from the conflicts committee and the board of directors of HK Management determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the bullet points above, then it will be presumed that, in making its decision, the board of directors, which may include board members affected by the conflict of interest, acted in good faith and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. These standards reduce the obligations to which our general partner would otherwise be held.

By purchasing our common units, each common unitholder automatically agrees to be bound by the provisions in the partnership agreement, including the provisions discussed above. This is in accordance with the policy of the Delaware Act favoring the principle of freedom of contract and the enforceability of partnership agreements. The failure of a limited partner or assignee to sign a partnership agreement does not render the partnership agreement unenforceable against such limited partner or assignee.

We must indemnify our general partner, the officers, directors and managers of HK Management, and certain other specified persons, to the fullest extent permitted by law, against liabilities, costs and expenses incurred by our general partner or these other persons. We must provide this indemnification unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that these persons acted in bad faith or engaged in fraud or willful misconduct. We must also provide this indemnification for criminal proceedings unless our general partner or these other persons acted with knowledge that their conduct was unlawful. Thus, our general partner could be indemnified for its negligent acts if it meets the requirements set forth above. To the extent these provisions purport to include indemnification for liabilities arising under the Securities Act, in the opinion of the SEC, such indemnification is contrary to public policy and, therefore, unenforceable. See “The Partnership Agreement — Indemnification.”

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DESCRIPTION OF THE COMMON UNITS

The Units

The common units and the subordinated units are separate classes of limited partner interests in us. The holders of units are entitled to participate in partnership distributions and exercise the rights or privileges available to limited partners under our partnership agreement. For a description of the relative rights and preferences of holders of common units and subordinated units in and to partnership distributions, please read this section and “Our Cash Distribution Policy and Restrictions on Distributions.” For a description of the rights and privileges of limited partners under our partnership agreement, including voting rights, see “The Partnership Agreement.”

Transfer Agent and Registrar

Duties. American Stock Transfer & Trust Company will serve as registrar and transfer agent for the common units. We will pay all fees charged by the transfer agent for transfers of common units except the following that must be paid by unitholders:

• surety bond premiums to replace lost or stolen certificates, taxes and other governmental charges;

• special charges for services requested by a common unitholder; and

• other similar fees or charges.

There will be no charge to unitholders for disbursements of our cash distributions. We will indemnify the transfer agent, its agents and each of their stockholders, directors, officers and employees against all claims and losses that may arise out of acts performed or omitted for its activities in that capacity, except for any liability due to any gross negligence or intentional misconduct of the indemnified person or entity.

Resignation or Removal. The transfer agent may resign, by notice to us, or be removed by us. The resignation or removal of the transfer agent will become effective upon our appointment of a successor transfer agent and registrar and its acceptance of the appointment. If no successor has been appointed and has accepted the appointment within 30 days after notice of the resignation or removal, our general partner may act as the transfer agent and registrar until a successor is appointed.

Transfer of Common Units

The transfer of the common units to persons that purchase directly from the underwriters will be accomplished through the proper completion, execution and delivery of a transfer application by the investor. Any later transfers of a common unit will not be recorded by the transfer agent or recognized by us unless the transferee executes and delivers a properly completed transfer application. By executing and delivering a transfer application, the transferee of common units:

• becomes the record holder of the common units and is an assignee until admitted into our partnership as a substituted limited partner;

• automatically requests admission as a substituted limited partner in our partnership;

• executes and agrees to be bound by the terms and conditions of our partnership agreement;

• represents that the transferee has the capacity, power and authority to enter into our partnership agreement;

• grants powers of attorney to the officers of HK Management and any liquidator of us as specified in our partnership agreement;

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• gives the consents, covenants, representations and approvals contained in our partnership agreement, such as the approval of all transactions and agreements we are entering into in connection with our formation and this offering; and

• certifies:

• that the transferee is an individual or is an entity subject to United States federal income taxation on the income generated by us; or

• that, if the transferee is an entity not subject to United States federal income taxation on the income generated by us, as in the case, for example, of a mutual fund taxed as a regulated investment company or a partnership, all the entity’s owners are subject to United States federal income taxation on the income generated by us.

An assignee will become a substituted limited partner of our partnership for the transferred common units automatically upon the recording of the transfer on our books and records. Our general partner will cause any unrecorded transfers for which a properly completed and duly executed transfer application has been received to be recorded on our books and records no less frequently than quarterly.

A transferee’s broker, agent or nominee may, but is not obligated to, complete, execute and deliver a transfer application. We are entitled to treat the nominee holder of a common unit as the absolute owner. In that case, the beneficial holder’s rights are limited solely to those that it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee holder.

Common units are securities and are transferable according to the laws governing transfer of securities. In addition to other rights acquired upon transfer, the transferor gives the transferee the right to request admission as a substituted limited partner in our partnership for the transferred common units. A purchaser or transferee of common units who does not execute and deliver a properly completed transfer application obtains only:

• the right to assign the common unit to a purchaser or other transferee; and

• the right to transfer the right to seek admission as a substituted limited partner in our partnership for the transferred common units.

Thus, a purchaser or transferee of common units who does not execute and deliver a properly completed transfer application:

• will not receive cash distributions;

• will not be allocated any of our income, gain, deduction, losses or credits for federal income tax or other tax purposes;

• may not receive some federal income tax information or reports furnished to record holders of common units; and

• will have no voting rights;

unless the common units are held in a nominee or “street name” account and the nominee or broker has executed and delivered a transfer application and certification as to itself and any beneficial holders.

The transferor of common units has a duty to provide the transferee with all information that may be necessary to transfer the common units. The transferor does not have a duty to ensure the execution of the transfer application by the transferee and has no liability or responsibility if the transferee neglects or chooses not to execute and deliver a properly completed transfer application to the transfer agent. See “The Partnership Agreement — Status as Limited Partner.”

Until a common unit has been transferred on our books, we and the transfer agent may treat the record holder of the unit as the absolute owner for all purposes, except as otherwise required by law or stock exchange regulations.

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THE PARTNERSHIP AGREEMENT

The following is a summary of the material provisions of our partnership agreement. The form of our partnership agreement is included in this prospectus as Appendix A. We will provide prospective investors with a copy of our partnership agreement upon request at no charge.

We summarize the following provisions of our partnership agreement elsewhere in this prospectus:

• with regard to distributions of available cash, see “How We Will Make Cash Distributions”;

• with regard to the fiduciary duties of our general partner, see “Conflicts of Interest and Fiduciary Duties”;

• with regard to the transfer of common units, see “Description of the Common Units — Transfer of Common Units”; and

• with regard to allocations of taxable income and taxable loss, see “Material Tax Consequences.”

Organization and Duration

Our partnership was organized in October 2007 and will have a perpetual existence.

Purpose

Our purpose under the partnership agreement is limited to any business activity that is approved by our general partner and that lawfully may be conducted by a limited partnership organized under Delaware law, provided that our general partner shall not cause us to engage, directly or indirectly, in any business activity that our general partner determines would cause us to be treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes.

Although our general partner has the ability to cause us and our subsidiaries to engage in activities other than the business of acquiring, developing, and producing oil and natural gas properties and marketing and transporting oil and natural gas, our general partner has no current plans to do so and may decline to do so free of any fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interests of us or the limited partners. Our general partner is authorized in general to perform all acts it determines to be necessary or appropriate to carry out our purposes and to conduct our business.

Power of Attorney

Each limited partner, and each person who acquires a unit from a unitholder, by accepting the common unit, automatically grants to our general partner and, if appointed, a liquidator, a power of attorney to, among other things, execute and file documents required for our qualification, continuance or dissolution. The power of attorney also grants our general partner the authority to amend, and to make consents and waivers under, our partnership agreement.

Cash Distributions

Our partnership agreement specifies the manner in which we will make cash distributions to holders of our common and subordinated units as well as to our general partner with respect to its general partner interest and its incentive distribution rights. For a description of these cash distribution provisions, see “How We Will Make Cash Distributions.”

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Capital Contributions

Unitholders are not obligated to make additional capital contributions, except as described below under “— Limited Liability.” Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its 2% general partner interest if we issue additional units after the offering. Our general partner’s 2% interest, and the percentage of our cash distributions to which it is entitled, will be proportionately reduced if we issue additional units and our general partner does not contribute a proportionate amount of capital to us to maintain its 2% general partner interest. Our general partner will be entitled to make a capital contribution in order to maintain its 2% general partner interest in the form of a contribution to us of common units based on the current market value of the contributed common units.

Voting Rights

The following is a summary of the unitholder vote required for the matters specified below. Matters requiring the approval of a “unit majority” require:

• during the subordination period, the approval of a majority of the common units, excluding those common units held by our general partner and its affiliates, and a majority of the subordinated units, voting as separate classes;

• after the subordination period, the approval of a majority of the common units and Class B units, if any, voting as a single class; and

• in voting their common, Class B and subordinated units, our general partner and its affiliates will have no fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interests of us or the limited partners.

Issuance of additional units No approval right.

Amendment of the partnership agreement Certain amendments may be made by the general partner without the approval of the unitholders. Other amendments generally require the approval of a unit majority. See “— Amendment of the Partnership Agreement.”

Merger of our partnership or the sale of all or substantially all of our assets Unit majority in certain circumstances. See “— Merger, Consolidation, Conversion, Sale or Other Disposition of Assets.”

Dissolution of our partnership Unit majority. See “— Termination and Dissolution.”

Continuation of our business upon dissolution Unit majority. See “— Termination and Dissolution.”

Withdrawal of the general partner Under most circumstances, the approval of a majority of the common units, excluding common units held by our general partner and its affiliates, is required for the withdrawal of our general partner prior to December 31, 2017 in a manner that would cause a dissolution of our partnership. See “— Withdrawal or Removal of the General Partner.”

Removal of the general partner Not less than 66 ²/3% of the outstanding units, voting as a single class, including units held by our general partner and its affiliates. See “ — Withdrawal or Removal of the General Partner.”

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Transfer of the general partner interest Our general partner may transfer all, but not less than all, of its general partner interest in us without a vote of our unitholders to an affiliate or another person in connection with its merger or consolidation with or into, or sale of all or substantially all of its assets to, such person. The approval of a majority of the common units, excluding common units held by the general partner and its affiliates, is required in other circumstances for a transfer of the general partner interest to a third party prior to December 31, 2017. See “— Transfer of General Partner Interest.”

Transfer of incentive distribution rights Our general partner may transfer any or all of the incentive distribution rights without a vote of our unitholders to an affiliate or another person as part of our general partner’s merger or consolidation with or into, or sale of all or substantially all of its assets or the sale of all of the ownership interests in such holder to, such person. The approval of a majority of the common units, excluding common units held by the general partner and its affiliates, is required in most other circumstances for a transfer of the incentive distribution rights to a third party prior to December 31, 2017. See “— Transfer of Incentive Distribution Rights.”

Transfer of ownership interests in our general partner No approval required at any time. See “— Transfer of Ownership Interests in the General Partner.”

Limited Liability

Assuming that a limited partner does not participate in the control of our business within the meaning of the Delaware Act and that he otherwise acts in conformity with the provisions of the partnership agreement, his liability under the Delaware Act will be limited, subject to possible exceptions, to the amount of capital he is obligated to contribute to us for his common units plus his share of any undistributed profits and assets. If it were determined, however, that the right, or exercise of the right, by the limited partners as a group:

• to remove or replace the general partner;

• to approve some amendments to the partnership agreement; or

• to take other action under the partnership agreement;

constituted “participation in the control” of our business for the purposes of the Delaware Act, then the limited partners could be held personally liable for our obligations under the laws of Delaware, to the same extent as the general partner. This liability would extend to persons who transact business with us who reasonably believe that the limited partner is a general partner. Neither the partnership agreement nor the Delaware Act specifically provides for legal recourse against the general partner if a limited partner were to lose limited liability through any fault of the general partner. While this does not mean that a limited partner could not seek legal recourse, we know of no precedent for this type of a claim in Delaware case law.

Under the Delaware Act, a limited partnership may not make a distribution to a partner if, after the distribution, all liabilities of the limited partnership, other than liabilities to partners on account of their partnership interests and liabilities for which the recourse of creditors is limited to specific property of the partnership, would exceed the fair value of the assets of the limited partnership. For the purpose of determining the fair value of the assets of a limited partnership, the Delaware Act provides that the fair value of property subject to liability for which recourse of creditors is limited shall be included in the assets of the limited

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partnership only to the extent that the fair value of that property exceeds the nonrecourse liability. The Delaware Act provides that a limited partner who receives a distribution and knew at the time of the distribution that the distribution was in violation of the Delaware Act shall be liable to the limited partnership for the amount of the distribution for three years. Under the Delaware Act, a substituted limited partner of a limited partnership is liable for the obligations of his assignor to make contributions to the partnership, except that such person is not obligated for liabilities unknown to him at the time he became a limited partner and that could not be ascertained from the partnership agreement.

Our subsidiaries conduct business in three states and we may have subsidiaries that conduct business in other states in the future. Maintenance of our limited liability as a limited partner of the operating partnership may require compliance with legal requirements in the jurisdictions in which the operating partnership conducts business, including qualifying our subsidiaries to do business there.

Limitations on the liability of limited partners for the obligations of a limited partner have not been clearly established in many jurisdictions. If, by virtue of our partnership interest in our operating partnership or otherwise, it were determined that we were conducting business in any state without compliance with the applicable limited partnership or limited liability company statute, or that the right or exercise of the right by the limited partners as a group to remove or replace the general partner, to approve some amendments to the partnership agreement, or to take other action under the partnership agreement constituted “participation in the control” of our business for purposes of the statutes of any relevant jurisdiction, then the limited partners could be held personally liable for our obligations under the law of that jurisdiction to the same extent as the general partner under the circumstances. We will operate in a manner that the general partner considers reasonable and necessary or appropriate to preserve the limited liability of the limited partners.

Issuance of Additional Securities

Our partnership agreement authorizes us to issue an unlimited number of additional partnership securities for the consideration and on the terms and conditions determined by our general partner without the approval of the unitholders.

It is possible that we will fund acquisitions through the issuance of additional common units, subordinated units or other partnership securities. Holders of any additional common units we issue will be entitled to share equally with the then-existing holders of common units in our distributions of available cash. In addition, the issuance of additional common units or other partnership securities may dilute the value of the interests of the then-existing holders of common units in our net assets.

In accordance with Delaware law and the provisions of our partnership agreement, we may also issue additional partnership securities that, as determined by our general partner, may have special voting rights to which the common units are not entitled. In addition, our partnership agreement does not prohibit the issuance by our subsidiaries of equity securities, which may effectively rank senior to the common units.

Upon issuance of additional partnership securities (other than the issuance of common units upon exercise by the underwriters of their option to purchase additional common units, the issuance of Class B units in connection with a reset of the target distribution levels relating to our general partner’s incentive distribution rights or the issuance of partnership securities upon conversion of outstanding partnership securities), our general partner will be entitled, but not required, to make additional capital contributions to the extent necessary to maintain its 2% general partner interest in us. Our general partner’s 2% interest in us will be reduced if we issue additional units in the future and our general partner does not contribute a proportionate amount of capital to us to maintain its 2% general partner interest. Moreover, our general partner will have the right, which it may from time to time assign in whole or in part to any of its affiliates, to purchase common units, subordinated units or other partnership securities whenever, and on the same terms that, we issue those securities to persons other than our general partner and its affiliates, to the extent necessary to maintain the percentage interest of the general

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partner and its affiliates, including such interest represented by common units and subordinated units, that existed immediately prior to each issuance. The holders of common units will not have preemptive rights to acquire additional common units or other partnership securities.

Amendment of the Partnership Agreement

General. Amendments to our partnership agreement may be proposed only by or with the consent of our general partner. However, our general partner will have no duty or obligation to propose any amendment and may decline to do so free of any fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interests of us or the limited partners. In order to adopt a proposed amendment, other than the amendments discussed below, our general partner is required to seek written approval of the holders of the number of units required to approve the amendment or call a meeting of the limited partners to consider and vote upon the proposed amendment. Except as described below, an amendment must be approved by a unit majority.

Prohibited Amendments. No amendment may be made that would:

• enlarge the obligations of any limited partner without its consent, unless approved by at least a majority of the type or class of limited partner interests so affected; or

• enlarge the obligations of, restrict in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable by us to our general partner or any of its affiliates without the consent of our general partner, which consent may be given or withheld at its option.

The provision of our partnership agreement preventing the amendments having the effects described in either of the clauses above can be amended upon the approval of the holders of at least 90% of the outstanding units voting together as a single class (including units owned by our general partner and its affiliates). Upon completion of the offering our general partner and its affiliates will own approximately % of the outstanding common and subordinated units.

No Unitholder Approval. Our general partner may generally make amendments to our partnership agreement without the approval of any limited partner or assignee to reflect:

• a change in our name, the location of our principal place of our business, our registered agent or our registered office;

• the admission, substitution, withdrawal or removal of partners in accordance with our partnership agreement;

• a change that our general partner determines to be necessary or appropriate to qualify or continue our qualification as a limited partnership or a partnership in which the limited partners have limited liability under the laws of any state or to ensure that neither we nor the operating partnership nor any of its subsidiaries will be treated as an association taxable as a corporation or otherwise taxed as an entity for federal income tax purposes;

• an amendment that is necessary, in the opinion of our counsel, to prevent us or our general partner or its directors, officers, agents or trustees from in any manner being subjected to the provisions of the Investment Company Act of 1940, the Investment Advisers Act of 1940, or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974, or ERISA, whether or not substantially similar to plan asset regulations currently applied or proposed;

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• an amendment that our general partner determines to be necessary or appropriate for the authorization of additional partnership securities or rights to acquire partnership securities, including any amendment that our general partner determines is necessary or appropriate in connection with:

• the adjustments of the minimum quarterly distribution, first target distribution and second target distribution in connection with the reset of our general partner’s incentive distribution rights as described under “How We Will Make Cash Distributions — General Partner’s Right to Reset Target Distribution Levels;” or

• the implementation of the provisions relating to our general partner’s right to reset its incentive distribution rights in exchange for Class B units; and

• any modification of the incentive distribution rights made in connection with the issuance of additional partnership securities or rights to acquire partnership securities, provided that, any such modifications and related issuance of partnership securities have received approval by a majority of the members of the conflicts committee of HK Management;

• any amendment expressly permitted in our partnership agreement to be made by our general partner acting alone;

• an amendment effected, necessitated or contemplated by a merger agreement that has been approved under the terms of our partnership agreement;

• any amendment that our general partner determines to be necessary or appropriate for the formation by us of, or our investment in, any corporation, partnership or other entity, as otherwise permitted by our partnership agreement;

• a change in our fiscal year or taxable year and related changes;

• conversions into, mergers with or conveyances to another limited liability entity that is newly formed and has no assets, liabilities or operations at the time of the conversion, merger or conveyance other than those it receives by way of the conversion, merger or conveyance; or

• any other amendments substantially similar to any of the matters described in the clauses above.

In addition, our general partner may make amendments to our partnership agreement without the approval of any limited partner if our general partner determines that those amendments:

• do not adversely affect in any material respect the limited partners considered as a whole or any particular class of limited partners as compared to other classes of limited partners;

• are necessary or appropriate to satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute;

• are necessary or appropriate to facilitate the trading of limited partner interests or to comply with any rule, regulation, guideline or requirement of any securities exchange on which the limited partner interests are or will be listed for trading;

• are necessary or appropriate for any action taken by our general partner relating to splits or combinations of units under the provisions of our partnership agreement; or

• are required to effect the intent expressed in this prospectus or the intent of the provisions of our partnership agreement or are otherwise contemplated by our partnership agreement.

Opinion of Counsel and Unitholder Approval. For amendments of the type not requiring unitholder approval, our general partner will not be required to obtain an opinion of counsel that an amendment will not result in a loss of limited liability to the limited partners or result in our being treated as an entity for federal income tax purposes in connection with any of the amendments. No other amendments to our partnership

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agreement will become effective without the approval of holders of at least 90% of the outstanding units voting as a single class unless we first obtain an opinion of counsel to the effect that the amendment will not affect the limited liability under applicable law of any of our limited partners.

In addition to the above restrictions, any amendment that would have a material adverse effect on the rights or preferences of any type or class of outstanding units in relation to other classes of units will require the approval of at least a majority of the type or class of units so affected. Any amendment that reduces the voting percentage required to take any action is required to be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute not less than the voting requirement sought to be reduced.

Merger, Consolidation, Conversion, Sale or Other Disposition of Assets

A merger, consolidation or conversion of us requires the prior consent of our general partner. However, our general partner will have no duty or obligation to consent to any merger, consolidation or conversion and may decline to do so free of any fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interest of us or the limited partners.

In addition, the partnership agreement generally prohibits our general partner, without the prior approval of the holders of a unit majority, from causing us to, among other things, sell, exchange or otherwise dispose of all or substantially all of our assets in a single transaction or a series of related transactions, including by way of merger, consolidation or other combination, or approving on our behalf the sale, exchange or other disposition of all or substantially all of the assets of our subsidiaries. Our general partner may, however, mortgage, pledge, hypothecate or grant a security interest in all or substantially all of our assets without that approval. Our general partner may also sell all or substantially all of our assets under a foreclosure or other realization upon those encumbrances without that approval. Finally, our general partner may consummate any merger without the prior approval of our unitholders if we are the surviving entity in the transaction, our general partner has received an opinion of counsel regarding limited liability and tax matters, the transaction would not result in a material amendment to the partnership agreement, each of our units will be an identical unit of our partnership following the transaction, and the partnership securities to be issued do not exceed 20% of our outstanding partnership securities immediately prior to the transaction.

If the conditions specified in the partnership agreement are satisfied, our general partner may convert us or any of our subsidiaries into a new limited liability entity or merge us or any of our subsidiaries into, or convey all of our assets to, a newly formed entity if the sole purpose of that conversion, merger or conveyance is to effect a mere change in our legal form into another limited liability entity, our general partner has received an opinion of counsel regarding limited liability and tax matters, and the governing instruments of the new entity provide the limited partners and the general partner with the same rights and obligations as contained in the partnership agreement. The unitholders are not entitled to dissenters’ rights of appraisal under the partnership agreement or applicable Delaware law in the event of a conversion, merger or consolidation, a sale of substantially all of our assets or any other similar transaction or event.

Termination and Dissolution

We will continue as a limited partnership until terminated under our partnership agreement. We will dissolve upon:

• the election of our general partner to dissolve us, if approved by the holders of units representing a unit majority;

• there being no limited partners, unless we are continued without dissolution in accordance with applicable Delaware law;

• the entry of a decree of judicial dissolution of our partnership; or

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• the withdrawal or removal of our general partner or any other event that results in its ceasing to be our general partner other than by reason of a transfer of its general partner interest in accordance with our partnership agreement or withdrawal or removal following approval and admission of a successor.

Upon a dissolution under the last clause above, the holders of a unit majority may also elect, within specific time limitations, to continue our business on the same terms and conditions described in our partnership agreement by appointing as a successor general partner an entity approved by the holders of units representing a unit majority, subject to our receipt of an opinion of counsel to the effect that:

• the action would not result in the loss of limited liability of any limited partner; and

• neither our partnership, our operating partnership nor any of our other subsidiaries would be treated as an association taxable as a corporation or otherwise be taxable as an entity for federal income tax purposes upon the exercise of that right to continue.

Liquidation and Distribution of Proceeds

Upon our dissolution, unless we are continued as a new limited partnership, the liquidator authorized to wind up our affairs will, acting with all of the powers of our general partner that are necessary or appropriate to liquidate our assets and apply the proceeds of the liquidation as described in “How We Will Make Cash Distributions — Distributions of Cash Upon Liquidation.” The liquidator may defer liquidation or distribution of our assets for a reasonable period of time or distribute assets to partners in kind if it determines that a sale would be impractical or would cause undue loss to our partners.

Withdrawal or Removal of the General Partner

Except as described below, our general partner has agreed not to withdraw voluntarily as our general partner prior to December 31, 2017 without obtaining the approval of the holders of at least a majority of the outstanding common units, excluding common units held by the general partner and its affiliates, and furnishing an opinion of counsel regarding limited liability and tax matters. On or after December 31, 2017, our general partner may withdraw as general partner without first obtaining approval of any unitholder by giving 90 days’ written notice, and that withdrawal will not constitute a violation of our partnership agreement. Notwithstanding the information above, our general partner may withdraw without unitholder approval upon 90 days’ notice to the limited partners if at least 50% of the outstanding common units are held or controlled by one person and its affiliates other than the general partner and its affiliates. In addition, the partnership agreement permits our general partner in some instances to sell or otherwise transfer all of its general partner interest in us without the approval of the unitholders. See “— Transfer of General Partner Interest” and “— Transfer of Incentive Distribution Rights.”

Upon withdrawal of our general partner under any circumstances, other than as a result of a transfer by our general partner of all or a part of its general partner interest in us, the holders of a unit majority, voting as separate classes, may select a successor to that withdrawing general partner. If a successor is not elected, or is elected but an opinion of counsel regarding limited liability and tax matters cannot be obtained, we will be dissolved, wound up and liquidated, unless within a specified period after that withdrawal, the holders of a unit majority agree in writing to continue our business and to appoint a successor general partner. See “— Termination and Dissolution.”

Our general partner may not be removed unless that removal is approved by the vote of the holders of not less than 66 ²/3% of the outstanding units, voting together as a single class, including units held by our general partner and its affiliates, and we receive an opinion of counsel regarding limited liability and tax matters. Any removal of our general partner is also subject to the approval of a successor general partner by the vote of the holders of a majority of the outstanding common units and Class B units, if any, voting as a separate class, and subordinated units, voting as a separate class. The ownership of more than 33 ¹/3% of the outstanding units by

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our general partner and its affiliates would give them the practical ability to prevent our general partner’s removal. At the closing of this offering, our general partner and its affiliates will own 54.5% of the outstanding common and subordinated units.

Our partnership agreement also provides that if our general partner is removed as our general partner under circumstances where cause does not exist and units held by the general partner and its affiliates are not voted in favor of that removal:

• the subordination period will end, and all outstanding subordinated units will immediately convert into common units on a one-for-one basis;

• any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and

• our general partner will have the right to convert its general partner interest and its incentive distribution rights into common units or to receive cash in exchange for those interests based on the fair market value of those interests at that time.

In the event of removal of a general partner under circumstances where cause exists or withdrawal of a general partner where that withdrawal violates our partnership agreement, a successor general partner will have the option to purchase the general partner interest and incentive distribution rights of the departing general partner for a cash payment equal to the fair market value of those interests. Under all other circumstances where a general partner withdraws or is removed by the limited partners, the departing general partner will have the option to require the successor general partner to purchase the general partner interest of the departing general partner and its incentive distribution rights for fair market value. In each case, this fair market value will be determined by agreement between the departing general partner and the successor general partner. If no agreement is reached, an independent investment banking firm or other independent expert selected by the departing general partner and the successor general partner will determine the fair market value. Or, if the departing general partner and the successor general partner cannot agree upon an expert, then an expert chosen by agreement of the experts selected by each of them will determine the fair market value.

If the option described above is not exercised by either the departing general partner or the successor general partner, the departing general partner’s general partner interest and its incentive distribution rights will automatically convert into common units equal to the fair market value of those interests as determined by an investment banking firm or other independent expert selected in the manner described in the preceding paragraph.

In addition, we will be required to reimburse the departing general partner for all amounts due the departing general partner, including, without limitation, all employee-related liabilities, including severance liabilities, incurred for the termination of any employees employed by the departing general partner or its affiliates for our benefit.

Transfer of General Partner Interest

Except for transfer by our general partner of all, but not less than all, of its general partner interest to:

• an affiliate of our general partner (other than an individual); or

• another entity as part of the merger or consolidation of our general partner with or into another entity or the transfer by our general partner of all or substantially all of its assets to another entity,

our general partner may not transfer all or any of its general partner interest to another person prior to December 31, 2017 without the approval of the holders of at least a majority of the outstanding common units, excluding common units held by our general partner and its affiliates. As a condition of this transfer, the

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transferee must assume, among other things, the rights and duties of our general partner, agree to be bound by the provisions of our partnership agreement, and furnish an opinion of counsel regarding limited liability and tax matters.

Our general partner and its affiliates may at any time transfer units to one or more persons, without unitholder approval, except that they may not transfer subordinated units to us.

Transfer of Ownership Interests in the General Partner

At any time, Petrohawk and its affiliates may sell or transfer all or part of their partnership interests in our general partner, or their membership interest in HK Management, the general partner of our general partner, to an affiliate or third party without the approval of our unitholders.

Transfer of Incentive Distribution Rights

Our general partner or its affiliates or a subsequent holder may transfer its incentive distribution rights to an affiliate of the holder (other than an individual) or another entity as part of the merger or consolidation of such holder with or into another entity, the sale of all of the ownership interest in the holder or the sale of all or substantially all of its assets to, that entity without the prior approval of the unitholders. Prior to December 31, 2017, other transfers of incentive distribution rights will require the affirmative vote of holders of a majority of the outstanding common units, excluding common units held by our general partner and its affiliates. On or after December 31, 2017, the incentive distribution rights will be freely transferable.

Change of Management Provisions

Our partnership agreement contains specific provisions that are intended to discourage a person or group from attempting to remove HK Energy Partners GP LP as our general partner or otherwise change our management. If any person or group other than our general partner and its affiliates acquires beneficial ownership of 20% or more of any class of units, that person or group loses voting rights on all of its units. This loss of voting rights does not apply to any person or group that acquires the units from our general partner or its affiliates and any transferees of that person or group approved by our general partner or to any person or group who acquires the units with the prior approval of the board of directors of HK Management.

Our partnership agreement also provides that if our general partner is removed as our general partner under circumstances where cause does not exist and units held by our general partner and its affiliates are not voted in favor of that removal:

• the subordination period will end and all outstanding subordinated units will immediately convert into common units on a one-for-one basis;

• any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and

• our general partner will have the right to convert its general partner units and its incentive distribution rights into common units or to receive cash in exchange for those interests based on the fair market value of those interests at that time.

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Limited Call Right

If at any time our general partner and its affiliates own more than 80% of the then-issued and outstanding limited partner interests of any class, our general partner will have the right, which it may assign in whole or in part to any of its affiliates or to us, to acquire all, but not less than all, of the limited partner interests of the class held by unaffiliated persons as of a record date to be selected by our general partner, on at least 10 but not more than 60 days notice. The purchase price in the event of this purchase is the greater of:

• the highest cash price paid by either of our general partner or any of its affiliates for any limited partner interests of the class purchased within the 90 days preceding the date on which our general partner first mails notice of its election to purchase those limited partnership interests; and

• the current market price as of the date three days before the date the notice is mailed.

As a result of our general partner’s right to purchase outstanding limited partner interests, a holder of limited partner interests may have his limited partner interests purchased at a price that may be lower than market prices at various times prior to such purchase or lower than a unitholder may anticipate the market price to be in the future. The tax consequences to a unitholder of the exercise of this call right are the same as a sale by that unitholder of his common units in the market. See “Material Tax Consequences — Disposition of Units.”

The general partner’s right to purchase common units pursuant to this limited call right will be subject to the general partner’s compliance with applicable securities and other laws.

Meetings; Voting

Except as described below regarding a person or group owning 20% or more of any class of units then outstanding, record holders of units on the record date will be entitled to notice of, and to vote at, meetings of our limited partners and to act upon matters for which approvals may be solicited. Units that are owned by Non-Eligible Holders will be voted by our general partner and our general partner will distribute the votes on those units in the same ratios as the votes of limited partners on other units are cast.

Our general partner does not anticipate that any meeting of unitholders will be called in the foreseeable future. Any action that is required or permitted to be taken by the unitholders may be taken either at a meeting of the unitholders or without a meeting if consents in writing describing the action so taken are signed by holders of the number of units necessary to authorize or take that action at a meeting. Meetings of the unitholders may be called by our general partner or by unitholders owning at least 20% of the outstanding units of the class for which a meeting is proposed. Unitholders may vote either in person or by proxy at meetings. The holders of a majority of the outstanding units of the class or classes for which a meeting has been called represented in person or by proxy will constitute a quorum unless any action by the unitholders requires approval by holders of a greater percentage of the units, in which case the quorum will be the greater percentage.

Each record holder of a unit has a vote according to his percentage interest in us, although additional limited partner interests having special voting rights could be issued. See “— Issuance of Additional Securities.” However, if at any time any person or group acquires, in the aggregate, beneficial ownership of 20% or more of any class of units then outstanding, other than our general partner and its affiliates, or their transferees and persons who acquired such units with the prior approval of the board of directors of our general partner, that person or group will lose voting rights on all of its units and the units may not be voted on any matter and will not be considered to be outstanding when sending notices of a meeting of unitholders, calculating required votes, determining the presence of a quorum or for other similar purposes. Common units held in nominee or street name account will be voted by the broker or other nominee in accordance with the instruction of the beneficial owner unless the arrangement between the beneficial owner and his nominee provides otherwise. Except as our partnership agreement otherwise provides, subordinated units will vote together with common units and Class B units as a single class.

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Any notice, demand, request, report or proxy material required or permitted to be given or made to record holders of common units under our partnership agreement will be delivered to the record holder by us or by the transfer agent.

Status as Limited Partner

By transfer of common units in accordance with our partnership agreement, each transferee of common units shall be admitted as a limited partner with respect to the common units transferred when such transfer and admission are reflected in our books and records. Except as described under “— Limited Liability,” the common units will be fully paid, and unitholders will not be required to make additional contributions.

Non-Eligible Holders; Redemption

To comply with certain U.S. laws relating to the ownership of interests in oil and natural gas leases on federal lands, transferees are required to fill out a properly completed transfer application certifying, and our general partner, acting on our behalf, may at any time require each unitholder to re-certify, that the unitholder is an Eligible Holder. As used in our partnership agreement, an Eligible Holder means a person or entity qualified to hold an interest in oil and natural gas leases on federal lands. As of the date hereof, Eligible Holder means:

• a citizen of the United States;

• a corporation organized under the laws of the United States or of any state thereof;

• a public body, including a municipality; or

• an association of United States citizens, such as a partnership or limited liability company, organized under the laws of the United States or of any state thereof, but only if such association does not have any direct or indirect foreign ownership, other than foreign ownership of stock in a parent corporation organized under the laws of the United States or of any state thereof.

For the avoidance of doubt, onshore mineral leases or any direct or indirect interest therein may be acquired and held by aliens only through stock ownership, holding or control in a corporation organized under the laws of the United States or of any state thereof. This certification can be changed in any manner our general partner determines is necessary or appropriate to implement its original purpose.

If a transferee or a unitholder, as the case may be, fails to furnish:

• a transfer application containing the required certification,

• a re-certification containing the required certification within 30 days after request, or

• provides a false certification,

then, as the case may be, such transfer will be void or we will have the right, which we may assign to any of our affiliates, to acquire all but not less than all of the units held by such unitholder. Further, the units held by such unitholder will not be entitled to any allocations of income or loss, distributions or voting rights.

The purchase price will be paid in cash or delivery of a promissory note, as determined by our general partner. Any such promissory note will bear interest at the rate of 5% annually and be payable in three equal annual installments of principal and accrued interest, commencing one year after the redemption date.

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Indemnification

Under our partnership agreement, in most circumstances, we will indemnify the following persons, to the fullest extent permitted by law, from and against all losses, claims, damages or similar events:

• our general partner;

• our general partner’s general partner;

• any departing general partner;

• any person who is or was an affiliate of or owner of an equity interest in a general partner or any departing general partner;

• any person who is or was a director, officer, member, partner, fiduciary or trustee of any entity set forth in the preceding four bullet points;

• any person who is or was serving as director, officer, member, partner, fiduciary or trustee of another person at the request of our general partner or any departing general partner; and

• any person designated by our general partner.

Any indemnification under these provisions will only be out of our assets. Unless it otherwise agrees, our general partner will not be personally liable for, or have any obligation to contribute or lend funds or assets to us to enable us to effectuate, indemnification. We may purchase insurance against liabilities asserted against and expenses incurred by persons for our activities, regardless of whether we would have the power to indemnify the person against liabilities under our partnership agreement.

Reimbursement of Expenses

Our partnership agreement requires us to reimburse our general partner for all direct and indirect expenses it incurs or payments it makes on our behalf and all other expenses allocable to us or otherwise incurred by our general partner in connection with operating our business. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. The general partner is entitled to determine in good faith the expenses that are allocable to us.

Books and Reports

Our general partner is required to keep appropriate books of our business at our principal offices. The books will be maintained for both tax and financial reporting purposes on an accrual basis. For tax and fiscal reporting purposes, our fiscal year is the calendar year.

We will furnish or make available to record holders of common units, within 120 days after the close of each fiscal year, an annual report containing audited financial statements and a report on those financial statements by our independent public accountants. Except for our fourth quarter, we will also furnish or make available summary financial information within 90 days after the close of each quarter.

We will furnish each record holder of a unit with information reasonably required for tax reporting purposes within 90 days after the close of each calendar year. This information is expected to be furnished in summary form so that some complex calculations normally required of partners can be avoided. Our ability to furnish this summary information to unitholders will depend on the cooperation of unitholders in supplying us with specific information. Every unitholder will receive information to assist him in determining his federal and state tax liability and filing his federal and state income tax returns, regardless of whether he supplies us with information.

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Right to Inspect Our Books and Records

Our partnership agreement provides that a limited partner can, for a purpose reasonably related to his interest as a limited partner, upon reasonable written demand stating the purpose of such demand and at his own expense, have furnished to him:

• a current list of the name and last known address of each partner;

• a copy of our tax returns;

• information as to the amount of cash, and a description and statement of the agreed value of any other property or services, contributed or to be contributed by each partner and the date on which each partner became a partner;

• copies of our partnership agreement, our certificate of limited partnership, related amendments and powers of attorney under which they have been executed;

• information regarding the status of our business and financial condition; and

• any other information regarding our affairs as is just and reasonable.

Our general partner may, and intends to, keep confidential from the limited partners trade secrets or other information the disclosure of which our general partner believes in good faith is not in our best interests or that we are required by law or by agreements with third parties to keep confidential.

Registration Rights

Under our partnership agreement, we have agreed to register for resale under the Securities Act and applicable state securities laws any common units, subordinated units or other partnership securities proposed to be sold by our general partner, its affiliates or their assignees if an exemption from the registration requirements is not otherwise available. These registration rights continue for two years following any withdrawal or removal of HK Energy Partners GP LP as general partner. We are obligated to pay all expenses incidental to the registration, excluding underwriting discounts and a structuring fee. See “Units Eligible for Future Sale.”

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UNITS ELIGIBLE FOR FUTURE SALE

After the sale of the common units offered hereby and assuming that the underwriters do not exercise their option to purchase additional units, our management and Petrohawk and its affiliates will hold an aggregate of 5,904,048 common units and 5,189,742 subordinated units. The sale of these units could have an adverse impact on the price of the common units or on any trading market that may develop.

The common units sold in the offering will generally be freely transferable without restriction or further registration under the Securities Act, except that any common units owned by an “affiliate” of ours may not be resold publicly except in compliance with the registration requirements of the Securities Act or under an exemption under Rule 144 or otherwise. Rule 144 permits securities acquired by an affiliate of the issuer to be sold into the market in an amount that does not exceed, during any three-month period, the greater of:

• 1% of the total number of the securities outstanding; or

• the average weekly reported trading volume of the common units for the four calendar weeks prior to the sale.

Sales under Rule 144 are also subject to specific manner of sale provisions, holding period requirements, notice requirements and the availability of current public information about us. A person who is not deemed to have been an affiliate of ours at any time during the three months preceding a sale, and who has beneficially owned his common units for at least two years, would be entitled to sell common units under Rule 144 without regard to the public information requirements, volume limitations, manner of sale provisions and notice requirements of Rule 144.

The partnership agreement does not restrict our ability to issue any partnership securities at any time. Any issuance of additional common units or other equity securities would result in a corresponding decrease in the proportionate ownership interest in us represented by, and could adversely affect the cash distributions to and market price of, common units then outstanding. See “The Partnership Agreement — Issuance of Additional Securities.”

Under our partnership agreement, our general partner and its affiliates have the right to cause us to register under the Securities Act and state securities laws the offer and sale of any common units, subordinated units or other partnership securities that they hold. Subject to the terms and conditions of our partnership agreement, these registration rights allow our general partner and its affiliates or their assignees holding any units or other partnership securities to require registration of any of these units or other partnership securities and to include them in a registration by us of other units, including units offered by us or by any unitholder. Our general partner will continue to have these registration rights for two years following its withdrawal or removal as our general partner. In connection with any registration of this kind, we will indemnify each unitholder participating in the registration and its officers, directors and controlling persons from and against any liabilities under the Securities Act or any state securities laws arising from the registration statement or prospectus. We will bear all costs and expenses incidental to any registration, excluding any underwriting discounts and a structuring fee. Except as described below, our general partner and its affiliates may sell their units or other partnership interests in private transactions at any time, subject to compliance with applicable laws.

Petrohawk, our partnership, HK Management, our general partner and the directors and executive officers of HK Management, have agreed not to sell any common units they beneficially own for a period of 180 days from the date of this prospectus. For a description of these lock-up provisions, see “Underwriting –– Lock-Up Agreements.”

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MATERIAL TAX CONSEQUENCES

This section is a discussion of the material tax consequences that may be relevant to prospective unitholders who are individual citizens or residents of the United States and, unless otherwise noted in the following discussion, is the opinion of Thompson & Knight LLP, counsel to us, insofar as it relates to matters of U.S. federal income tax law and legal conclusions with respect to those matters. This section is based on current provisions of the Internal Revenue Code, existing and proposed regulations and current administrative rulings and court decisions, all of which are subject to change. Later changes in these authorities may cause the tax consequences to vary substantially from the consequences described below. Unless the context otherwise requires, references in this section to “us” or “we” are references to HK Energy Partners LP and our operating subsidiaries.

This section does not address all federal income tax matters that affect us or the unitholders. Furthermore, this section focuses on unitholders who are individual citizens or residents of the United States and has only limited application to corporations, estates, trusts, non-resident aliens, or other unitholders subject to specialized tax treatment, such as tax-exempt institutions, non-U.S. persons, individual retirement accounts (IRAs), employee benefit plans, real estate investment trusts (REITs), or mutual funds. Accordingly, we urge each prospective unitholder to consult, and depend on, his own tax advisor in analyzing the federal, state, local, and foreign tax consequences particular to him of the ownership or disposition of our units.

No ruling has been or will be requested from the IRS regarding any matter that affects us or prospective unitholders. Instead, we will rely on opinions and advice of Thompson & Knight LLP. Unlike a ruling, an opinion of counsel represents only that counsel’s best legal judgment and does not bind the IRS or the courts. Accordingly, the opinions and statements made in this discussion may not be sustained by a court if contested by the IRS. Any contest of this sort with the IRS may materially and adversely impact the market for our units and the prices at which our units trade. In addition, the costs of any contest with the IRS, principally legal, accounting and related fees, will result in a reduction in cash available for distribution to our unitholders and thus will be borne directly by our unitholders. Furthermore, the tax treatment of us, or of an investment in us, may be significantly modified by future legislative or administrative changes or court decisions. Any modifications may or may not be retroactively applied.

All statements regarding matters of law and legal conclusions set forth below, unless otherwise noted, are the opinion of Thompson & Knight LLP and are based on the accuracy of the representations made by us. Statements of fact do not represent opinions of Thompson & Knight LLP.

For the reasons described below, Thompson & Knight LLP has not rendered an opinion with respect to the following specific federal income tax issues:

(1) the treatment of a unitholder whose units are loaned to a short seller to cover a short sale of units (see “ — Tax Consequences of Unit Ownership — Treatment of Short Sales”);

(2) whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury Regulations (see “ — Disposition of Units — Tax Allocations Between Transferors and Transferees”);

(3) whether percentage depletion will be available to a unitholder or the extent of the percentage depletion deduction available to any unitholder (see “ — Tax Treatment of Operations — Depletion Deductions”);

(4) whether the deduction related to U.S. production activities will be available to a unitholder or the extent of any such deduction to any unitholder (see “ — Tax Treatment of Operations — Deduction for U.S. Production Activities”); and

(5) whether our method for depreciating Section 743 adjustments is sustainable in certain cases (see “ — Tax Consequences of Unit Ownership — Section 754 Election” and “ — Uniformity of Units”).

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Partnership Status

A partnership is not a taxable entity and incurs no federal income tax liability. Instead, each partner in a partnership is required to take into account his share of items of income, gain, loss, and deduction of the partnership in computing his federal income tax liability, regardless of whether cash distributions are made to him. Distributions by a partnership to a partner generally are not taxable to the partner, unless the amount of cash distributed to him is in excess of his adjusted tax basis in his partnership interest.

Section 7704 of the Internal Revenue Code provides that publicly traded partnerships will, as a general rule, be taxed as corporations. However, an exception, referred to in this discussion as the “Qualifying Income Exception,” exists with respect to publicly traded partnerships 90% or more of the gross income of which for every taxable year consists of “qualifying income.” Qualifying income includes income and gains derived from the exploration, development, mining or production, processing, refining, transportation, and marketing of natural resources, including oil, natural gas, and products thereof. Other types of qualifying income include interest (other than from a financial business), dividends, gains from the sale of real property, and gains from the sale or other disposition of capital assets (or property described in Code Section 1231(b)) held for the production of income that otherwise constitutes qualifying income. We estimate that less than     % of our current gross income does not constitute qualifying income; however, this estimate could change from time to time. Based on and subject to this estimate, the factual representations made by us, and a review of the applicable legal authorities, Thompson & Knight LLP is of the opinion that more than 90% of our current gross income constitutes qualifying income. The portion of our income that is qualifying income may change from time to time.

No ruling has been or will be sought from the IRS, and the IRS has made no determination as to our status or the status of our operating subsidiaries for federal income tax purposes or whether our operations generate “qualifying income” under Section 7704 of the Internal Revenue Code. Instead, we will rely on the opinion of Thompson & Knight LLP on such matters. Thompson & Knight LLP is of the opinion, based upon the Internal Revenue Code, its regulations, published revenue rulings, court decisions, and the representations described below, that we will be classified as a partnership, and each of our operating subsidiaries will be disregarded as an entity separate from us, for U.S. federal income tax purposes.

In rendering its opinion, Thompson & Knight LLP has relied on factual representations made by us. The representations made by us upon which Thompson & Knight LLP has relied include:

(1) Neither we, nor any of our operating subsidiaries, have elected or will elect to be treated as a corporation; and

(2) For each taxable year, more than 90% of our gross income will be income that Thompson & Knight LLP has opined or will opine is “qualifying income” within the meaning of Section 7704(d) of the Internal Revenue Code.

If we fail to meet the Qualifying Income Exception, other than a failure that is determined by the IRS to be inadvertent and that is cured within a reasonable time after discovery (in which case the IRS may also require us to make adjustments with respect to our unitholders or pay other amounts) we will be treated as if we had transferred all of our assets, subject to liabilities, to a newly formed corporation, on the first day of the year in which we fail to meet the Qualifying Income Exception, in return for stock in that corporation and then distributed that stock to the unitholders in liquidation of their interests in us. This deemed contribution and liquidation should be tax-free to unitholders and us, so long as we, at that time, do not have liabilities in excess of the tax basis of our assets. Thereafter, we would be treated as a corporation for federal income tax purposes.

If we were treated as a corporation in any taxable year, either as a result of a failure to meet the Qualifying Income Exception or otherwise, our items of income, gain, loss, and deduction would be reflected only on our tax return rather than being passed through to the unitholders, and our net income would be taxed to us at corporate rates. In addition, any distribution made to a unitholder would be treated as taxable dividend income to the extent of our current or accumulated earnings and profits, or, in the absence of earnings and profits, a nontaxable return

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of capital to the extent of the unitholder’s tax basis in his units, and generally taxable capital gain to the extent of the excess over the unitholder’s tax basis in his units. Accordingly, taxation as a corporation would result in a material reduction in a unitholder’s cash flow and after-tax return and thus would likely result in a substantial reduction of the value of the units.

The remainder of this section is based on Thompson & Knight LLP’s opinion that we will be classified as a partnership for federal income tax purposes.

Limited Partner Status

Unitholders who have become limited partners of HK Energy Partners LP will be treated as partners of HK Energy Partners LP for federal income tax purposes. Also, assignees who are awaiting admission as partners, and unitholders whose units are held in street name or by a nominee and who have the right to direct the nominee in the exercise of all substantive rights attendant to the ownership of their units will be treated as partners of HK Energy Partners LP for federal income tax purposes.

A beneficial owner of units whose units have been transferred to a short seller to complete a short sale would appear to lose his status as a partner with respect to those units for federal income tax purposes. See “ — Tax Consequences of Unit Ownership — Treatment of Short Sales.”

Items of our income, gain, loss, or deduction would not appear to be reportable by a unitholder who is not a partner for federal income tax purposes, and any cash distributions received by a unitholder who is not a partner for federal income tax purposes would therefore appear to be fully taxable as ordinary income. These unitholders are urged to consult their own tax advisors with respect to their status as partners in us for federal income tax purposes.

The references to “unitholders” in the discussion that follows are to persons who are treated as partners in HK Energy Partners LP for U.S. federal income tax purposes.

Tax Consequences of Unit Ownership

Flow-Through of Taxable Income

We will not pay any federal income tax. Instead, each unitholder will be required to report on his income tax return his share of our income, gain, loss, and deduction without regard to whether corresponding cash distributions are received by him. Consequently, we may allocate income to a unitholder even if he has not received a cash distribution. Each unitholder will be required to include in income his allocable share of our income, gain, loss, and deduction for our taxable year or years ending with or within his taxable year. Our taxable year ends on December 31.

Treatment of Distributions

Distributions made by us to a unitholder generally will not be taxable to him for federal income tax purposes to the extent of his tax basis in his units immediately before the distribution. Cash distributions made by us to a unitholder in an amount in excess of his tax basis in his units generally will be considered to be gain from the sale or exchange of those units, taxable in accordance with the rules described under “ — Disposition of Units” below. To the extent that cash distributions made by us cause a unitholder’s “at risk” amount to be less than zero at the end of any taxable year, he must recapture any losses deducted in previous years. See “ — Limitations on Deductibility of Tax Losses.”

Any reduction in a unitholder’s share of our liabilities for which no partner bears the economic risk of loss, known as “nonrecourse liabilities,” will be treated as a distribution of cash to that unitholder. A decrease in a

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unitholder’s percentage interest in us because of our issuance of additional units will decrease his share of our nonrecourse liabilities and thus will result in a corresponding deemed distribution of cash, which may constitute a non-pro rata distribution. A non-pro rata distribution of money or property may result in ordinary income to a unitholder, regardless of his tax basis in his units, if the distribution reduces the unitholder’s share of our “unrealized receivables,” including recapture of intangible drilling costs, depletion and depreciation, and/or substantially appreciated “inventory items,” both as defined in Section 751 of the Internal Revenue Code, and collectively, “Section 751 Assets.” To that extent, he will be treated as having received his proportionate share of the Section 751 Assets and then having exchanged those assets with us in return for the non-pro rata portion of the actual distribution made to him. This latter deemed exchange generally will result in the unitholder’s realization of ordinary income. That income will equal the excess of (1) the non-pro rata portion of that distribution over (2) the unitholder’s tax basis (generally zero) for the share of Section 751 Assets deemed relinquished in the exchange.

Ratio of Taxable Income to Distributions

We estimate that a purchaser of our units in this offering who holds those units from the date of closing of this offering through the record date for distributions for the period ending December 31,         , will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be less than          of the cash distributed to the unitholder with respect to that period. We anticipate that thereafter, the ratio of allocable taxable income to cash distributions to the unitholders will increase. These estimates are based upon the assumption that gross income from operations will be sufficient to make estimated distributions on all units and other assumptions with respect to capital expenditures, cash flow, net working capital and anticipated cash distributions. These estimates and assumptions are subject to, among other things, numerous business, economic, regulatory, competitive and political uncertainties beyond our control. Further, the estimates are based on current tax law and tax reporting positions that we intend to adopt and with which the IRS could disagree. Accordingly, these estimates may not prove to be correct. The actual percentage of distributions that will constitute taxable income could be higher or lower, and any differences could be material and could materially affect the value of the units. For example, the ratio of allocable taxable income to cash distributions to a purchaser of units in this offering will be greater, and perhaps substantially greater, than our estimate with respect to the period described above if:

• gross income from operations exceeds the amount required to make quarterly distributions on all units at the minimum quarterly distribution rate, yet we only distribute the minimum quarterly distribution on all units; or

• we make a future offering of units and use the proceeds of the offering in a manner that does not produce substantial additional deductions during the period described above, such as to repay indebtedness outstanding at the time of this offering or to acquire property that is not eligible for depletion, depreciation or amortization for federal income tax purposes or that is depletable, depreciable or amortizable at a rate significantly slower than the rate applicable to our assets at the time of this offering.

Basis of Units

A unitholder’s initial tax basis for his units will be the amount he paid for the units plus his share of our nonrecourse liabilities. That tax basis will be increased by his share of our income and by any increases in his share of our nonrecourse liabilities and generally will be decreased, but not below zero, by distributions to him from us, by his share of our losses, by depletion deductions taken by him to the extent such deductions do not exceed his proportionate share of the adjusted tax basis of the underlying producing properties, by any decreases in his share of our nonrecourse liabilities and by his share of our expenditures that are not deductible in computing taxable income and are not required to be capitalized. A unitholder’s share of our nonrecourse liabilities will generally be based on his share of our profits. See “ — Disposition of Units — Recognition of Taxable Gain or Loss.”

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Limitations on Deductibility of Tax Losses

The deduction by a unitholder of his share of our taxable losses will be limited to his tax basis in his units and, in the case of an individual unitholder estate, trust or a corporate unitholder (if such corporate unitholder is taxable under Subchapter C and more than 50% of the value of its stock is owned directly or indirectly by or for five or fewer individuals or some tax-exempt organizations) to the amount for which the unitholder is considered to be “at risk” with respect to our activities, if that amount is less than his tax basis. A unitholder subject to these limitations must recapture losses deducted in previous years to the extent that distributions cause his at-risk amount to be less than zero at the end of any taxable year. Losses disallowed to a unitholder or recaptured as a result of these limitations will carry forward and will be allowable as a deduction in a later year to the extent that his tax basis or at-risk amount, whichever is the limiting factor, is subsequently increased, provided such losses are otherwise allowable. Upon the taxable disposition of a unit, any gain recognized by a unitholder can be offset by losses that were previously suspended by the at-risk limitation but may not be offset by losses suspended by the basis limitation. Any excess loss above that gain previously suspended by the at-risk or basis limitations is no longer utilizable.

In general, a unitholder will be at risk to the extent of his tax basis in his units, excluding any portion of that tax basis attributable to his share of our nonrecourse liabilities, reduced by any amount of money he borrows to acquire or hold his units, if the lender of those borrowed funds owns an interest in us, is related to the unitholder or can look only to the units for repayment. A unitholder’s at-risk amount will increase or decrease as the tax basis of the unitholder’s units increases or decreases, other than tax basis increases or decreases attributable to increases or decreases in his share of our nonrecourse liabilities. Moreover, a unitholder’s at-risk amount will decrease by the amount of the unitholder’s depletion deductions and will increase to the extent of the amount by which the unitholder’s percentage depletion deductions with respect to our property exceed the unitholder’s share of the tax basis of that property.

The at-risk limitation applies on an activity-by-activity basis, and in the case of natural gas and oil properties, each property is generally treated as a separate activity. Thus, a taxpayer’s interest in each oil or natural gas property is generally required to be treated separately so that a loss from any one property would be limited to the at-risk amount for that property and not the at-risk amount for all the taxpayer’s natural gas and oil properties. It is uncertain how this rule is implemented in the case of multiple natural gas and oil properties owned by a single entity treated as a partnership for federal income tax purposes. However, for taxable years ending on or before the date on which further guidance is published, the IRS will permit aggregation of oil or gas properties we own in computing a unitholder’s at-risk limitation with respect to us. If a unitholder were required to compute his at-risk amount separately with respect to each oil or gas property we own, he might not be allowed to utilize his share of losses or deductions attributable to a particular property even though he has a positive at-risk amount with respect to his units as a whole.

The passive loss limitation generally provides that individuals, estates, trusts, and some closely held corporations and personal service corporations are permitted to deduct losses from passive activities, which generally are defined as trade or business activities in which the taxpayer does not materially participate, only to the extent of the taxpayer’s income from those passive activities. The passive loss limitation is applied separately with respect to each publicly traded partnership. Consequently, any losses we generate will be available to offset only our passive income generated in the future and will not be available to offset income from other passive activities or investments, including our investments, a unitholder’s investments in other publicly traded partnerships, or a unitholder’s salary or active business income. If we dispose of all or only a part of our interest in an oil or gas property, unitholders will be able to offset their suspended passive activity losses from our activities against the gain, if any, on the disposition. Any previously suspended losses in excess of the amount of gain recognized will remain suspended. Passive losses that are not deductible because they exceed a unitholder’s share of income we generate may be deducted by the unitholder in full when he disposes of his entire investment in us in a fully taxable transaction with an unrelated party. The passive activity loss rules are applied after certain other applicable limitations on deductions, including the at-risk rules and the tax basis limitation.

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A unitholder’s share of our net income may be offset by any of our suspended passive losses, but it may not be offset by any other current or carryover losses from other passive activities, including those attributable to other publicly traded partnerships.

Limitations on Interest Deductions

The deductibility of a non-corporate taxpayer’s “investment interest expense” is generally limited to the amount of that taxpayer’s “net investment income.” Investment interest expense includes:

• interest on indebtedness properly allocable to property held for investment;

• our interest expense attributable to portfolio income; and

• the portion of interest expense incurred to purchase or carry an interest in a passive activity to the extent attributable to portfolio income.

The computation of a unitholder’s investment interest expense will take into account interest on any margin account borrowing or other loan incurred to purchase or carry a unit.

Net investment income includes gross income from property held for investment and amounts treated as portfolio income under the passive loss rules, less deductible expenses, other than interest, directly connected with the production of investment income, but generally does not include gains attributable to the disposition of property held for investment or qualified dividend income. The IRS has indicated that net passive income earned by a publicly traded partnership will be treated as investment income to its unitholders for purposes of the investment interest expense deduction limitation. In addition, the unitholder’s share of our portfolio income will be treated as investment income.

Entity-Level Collections

If we are required or elect under applicable law to pay any federal, state or local income tax on behalf of any unitholder or any former unitholder, we are authorized to pay those taxes from our funds. That payment, if made, will be treated as a distribution of cash to the unitholder on whose behalf the payment was made. If the payment is made on behalf of a unitholder whose identity cannot be determined, we are authorized to treat the payment as a distribution to all current unitholders. We are authorized to amend the partnership agreement in the manner necessary to maintain uniformity of intrinsic tax characteristics of units and to adjust later distributions, so that after giving effect to these distributions, the priority and characterization of distributions otherwise applicable under the partnership agreement is maintained as nearly as is practicable. Payments by us as described above could give rise to an overpayment of tax on behalf of a unitholder in which event the unitholder would be required to file a claim in order to obtain a credit or refund.

Allocation of Taxable Income, Gain, Loss and Deduction

In general, if we have a net profit, our items of taxable income, gain, loss, and deduction will be allocated among the unitholders in accordance with their percentage interests in us. At any time that distributions are made on the units in excess of distributions made on the subordinated units, or incentive distributions are made to our general partner, gross income will be allocated to the recipients to the extent of those distributions. If we have a net loss for an entire year, the loss generally will be first allocated to our unitholders according to their percentage interests in us to the extent of their positive capital account balances and, second, to our general partner.

Specified items of our income, gain, loss, and deduction will be allocated under Section 704(c) of the Internal Revenue Code to account for the difference between the tax basis and fair market value of our assets at the time of this offering, which assets are referred to in this discussion as “Contributed Property.” These

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Section 704(c) allocations are required to eliminate the difference between a partner’s “book” capital account, credited with the fair market value of Contributed Property, and the “tax” capital account, credited with the tax basis of Contributed Property, referred to in this discussion as the “book-tax disparity.” The effect of these allocations to a unitholder who purchases units in this offering will be essentially the same as if the tax basis of our assets were equal to their fair market value at the time of the offering.

For example, a substantial portion of our Contributed Property will be depletable property with a fair market value in excess of its tax basis. Section 704(c) principles generally will require that depletion deductions with respect to each such property be allocated disproportionately to purchasers of units in this offering and away from our general partner and its affiliates. To the extent these disproportionate allocations do not produce a result to holders of units similar to that which would be the case if all of our initial assets had a tax basis equal to their fair market value on the date this offering closes, purchasers of units in this offering will be allocated the additional tax deductions needed to produce that result as to any asset with respect to which we elect the remedial allocation method of taking into account the difference between the tax basis of the asset and its fair market value. Similar principles will apply to Contributed Property that is depreciable.

In the event we issue additional units or engage in certain other transactions in the future, “reverse Section 704(c) allocations,” similar to the Section 704(c) allocations described above, will be made to all holders of partnership interests, including purchasers of units in this offering, to account for the difference between the “book” basis for purposes of maintaining capital accounts and the fair market value of all property held by us at the time of the future transaction.

In addition, items of recapture income will be allocated to the extent possible to the unitholder who was allocated the deduction giving rise to the treatment of that gain as recapture income in order to minimize the recognition of ordinary income by other unitholders. Finally, although we do not expect that our operations will result in the creation of negative capital accounts, if negative capital accounts nevertheless result, items of our income and gain will be allocated in an amount and manner sufficient to eliminate the negative balance as quickly as possible.

An allocation of items of our income, gain, loss, or deduction, other than an allocation required by Section 704(c), will generally be given effect for federal income tax purposes in determining a unitholder’s share of an item of income, gain, loss, or deduction only if the allocation has substantial economic effect. In any other case, a unitholder’s share of an item will be determined on the basis of his interest in us, which will be determined by taking into account all the facts and circumstances, including:

• his relative contributions to us;

• the interests of all the unitholders in profits and losses;

• the interest of all the unitholders in cash flow; and

• the rights of all the unitholders to distributions of capital upon liquidation.

Thompson & Knight LLP is of the opinion that, with the exception of the issues described in “ — Tax Consequences of Unit Ownership — Section 754 Election,” “ — Uniformity of Units” and “ — Disposition of Units — Allocations Between Transferors and Transferees,” allocations under our partnership agreement will be given effect for federal income tax purposes in determining a unitholder’s share of an item of income, gain, loss, or deduction.

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Treatment of Short Sales

A unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of those units. If so, he would no longer be a partner for tax purposes with respect to those units during the period of the loan and may recognize gain or loss from the disposition. As a result, during this period:

• none of our income, gain, loss or deduction with respect to those units would be reportable by the unitholder;

• any cash distributions received by the unitholder with respect to those units would be fully taxable; and

• all of these distributions would appear to be ordinary income.

Thompson & Knight LLP has not rendered an opinion regarding the treatment of a unitholder whose units are loaned to a short seller. Therefore, unitholders desiring to assure their status as partners and avoid the risk of gain recognition are urged to modify any applicable brokerage account agreements to prohibit their brokers from loaning their units. The IRS has announced that it is studying issues relating to the tax treatment of short sales of partnership interests. See “ — Disposition of Units — Recognition of Taxable Gain or Loss.”

Alternative Minimum Tax

Each unitholder will be required to take into account his distributive share of any items of our income, gain, loss, or deduction for purposes of the alternative minimum tax. The current minimum tax rate for non-corporate taxpayers is 26% on the first $175,000 of alternative minimum taxable income in excess of the exemption amount and 28% on any additional alternative minimum taxable income. Prospective unitholders are urged to consult their tax advisors with respect to the impact of an investment in our units on their liability for the alternative minimum tax.

Tax Rates

In general, the highest effective federal income tax rate for individuals currently is 35% and the maximum federal income tax rate for net capital gains of an individual currently is 15% for gains prior to 2011 and 20% for gains recognized during 2011 and thereafter if the asset disposed of was held for more than 12 months at the time of disposition.

Section 754 Election

We will make the election permitted by Section 754 of the Internal Revenue Code. That election is irrevocable without the consent of the IRS. That election will generally permit us to adjust a unit purchaser’s tax basis in our assets (“inside basis”) under Section 743(b) of the Internal Revenue Code to reflect his purchase price. The Section 743(b) adjustment does not apply to a person who purchases units directly from us, and it belongs only to the purchaser and not to other unitholders. See, however, “ — Allocation of Taxable Income, Gain, Loss, and Deduction” above. For purposes of this discussion, a unitholder’s inside basis in our assets has two components: (1) his share of our tax basis in our assets (“common basis”) and (2) his Section 743(b) adjustment to that tax basis.

The timing of deductions attributable to our common basis in the Contributed Property generally will depend on the remaining cost recovery schedule of such assets at the time of the contribution to us. The timing of deductions attributable to Section 743(b) adjustments to our common basis will depend upon a number of factors, including the nature of the assets to which the adjustment is allocable, the extent to which the adjustment offsets any Section 704(c) gain or loss with respect to an asset and certain elections we make as to the manner in which we apply Section 704(c) principles with respect to an asset to which the adjustment is applicable. See “ — Allocation of Taxable Income, Gain, Loss and Deduction.” The timing of these deductions may affect the uniformity of our units. See “ — Uniformity of Units.”

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A Section 754 election is advantageous if the transferee’s tax basis in his units is higher than the units’ share of the aggregate tax basis of our assets immediately prior to the transfer. In that case, as a result of the election, the transferee would have, among other items, a greater amount of depletion and depreciation deductions and his share of any gain on a sale of our assets would be less. Conversely, a Section 754 election is disadvantageous if the transferee’s tax basis in his units is lower than those units’ share of the aggregate tax basis of our assets immediately prior to the transfer. Thus, the fair market value of the units may be affected either favorably or unfavorably by the election. A tax basis adjustment is required regardless of whether a Section 754 election is made in the case of a transfer of an interest in us if we have a substantial built-in loss immediately after the transfer, or if we distribute property and have a substantial tax basis reduction. Generally a built-in loss or a tax basis reduction is substantial if it exceeds $250,000.

The calculations involved in the Section 754 election are complex and will be made on the basis of assumptions as to the value of our assets and other matters. For example, the allocation of the Section 743(b) adjustment among our assets must be made in accordance with the Internal Revenue Code. The IRS could seek to reallocate some or all of any Section 743(b) adjustment we allocated to our tangible assets to goodwill instead. Goodwill, an intangible asset, is generally either nonamortizable or amortizable over a longer period of time and under a less accelerated method than our tangible assets. We cannot assure you that the determinations we make will not be successfully challenged by the IRS or that the resulting deductions will not be reduced or disallowed altogether. Should the IRS require a different tax basis adjustment to be made, and should, in our opinion, the expense of compliance exceed the benefit of the election, we may seek permission from the IRS to revoke our Section 754 election. If permission is granted, a subsequent purchaser of units may be allocated more income than he would have been allocated had the election not been revoked.

Tax Treatment of Operations

Accounting Method and Taxable Year

We will use the year ending December 31 as our taxable year and the accrual method of accounting for federal income tax purposes. Each unitholder will be required to include in his taxable income his share of our taxable income, gain, loss, and deduction for our taxable year ending within or with his taxable year. In addition, a unitholder who has a taxable year ending on a date other than December 31 and who disposes of all of his units following the close of our taxable year but before the close of his taxable year must include his share of our income, gain, loss, and deduction in income for his taxable year, with the result that he will be required to include in his taxable income for his taxable year his share of more than twelve months of our income, gain, loss, and deduction. See “ — Disposition of Units — Tax Allocations Between Transferors and Transferees.”

Depletion Deductions

Subject to the limitations on deductibility of taxable losses discussed above, unitholders will be entitled to deductions for the greater of either cost depletion or (if otherwise allowable) percentage depletion with respect to our natural gas and oil interests. Although the Internal Revenue Code requires each unitholder to compute his own depletion allowance and maintain records of his share of the adjusted tax basis of the underlying property for depletion and other purposes, we intend to furnish each of our unitholders with information relating to this computation for federal income tax purposes. Each unitholder, however, remains responsible for calculating his own depletion allowance and maintaining records of his share of the adjusted tax basis of the underlying property for depletion and other purposes.

Percentage depletion is generally available with respect to unitholders who qualify under the independent producer exemption contained in Section 613A(c) of the Internal Revenue Code. For this purpose, an independent producer is a person not directly or indirectly involved in the retail sale of oil, natural gas, or derivative products or the operation of a major refinery. Percentage depletion is calculated as an amount generally equal to 15% (and, in the case of marginal production, potentially a higher percentage) of the

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unitholder’s gross income from the depletable property for the taxable year. The percentage depletion deduction with respect to any property is limited to 100% of the taxable income of the unitholder from the property for each taxable year, computed without the depletion allowance. A unitholder that qualifies as an independent producer may deduct percentage depletion only to the extent the unitholder’s average daily production of domestic crude oil, or the natural gas equivalent, does not exceed 1,000 barrels. This depletable amount may be allocated between natural gas and oil production, with 6,000 cubic feet of domestic natural gas production regarded as equivalent to one barrel of crude oil. The 1,000-barrel limitation must be allocated among the independent producer and controlled or related persons and family members in proportion to the respective production by such persons during the period in question.

In addition to the foregoing limitations, the percentage depletion deduction otherwise available is limited to 65% of a unitholder’s total taxable income from all sources for the year, computed without the depletion allowance, net operating loss carrybacks, or capital loss carrybacks. Any percentage depletion deduction disallowed because of the 65% limitation may be deducted in the following taxable year if the percentage depletion deduction for such year plus the deduction carryover does not exceed 65% of the unitholder’s total taxable income for that year. The carryover period resulting from the 65% net income limitation is indefinite.

Unitholders that do not qualify under the independent producer exemption are generally restricted to depletion deductions based on cost depletion. Cost depletion deductions are calculated by (1) dividing the unitholder’s share of the adjusted tax basis in the underlying mineral property by the number of mineral units (barrels of oil and thousand cubic feet, or Mcf, of natural gas) remaining as of the beginning of the taxable year and (2) multiplying the result by the number of mineral units sold within the taxable year. The total amount of deductions based on cost depletion cannot exceed the unitholder’s share of the total adjusted tax basis in the property.

All or a portion of any gain recognized by a unitholder as a result of either the disposition by us of some or all of our natural gas and oil interests or the disposition by the unitholder of some or all of his units may be taxed as ordinary income to the extent of recapture of depletion deductions, except for percentage depletion deductions in excess of the tax basis of the property. The amount of the recapture is generally limited to the amount of gain recognized on the disposition.

The foregoing discussion of depletion deductions does not purport to be a complete analysis of the complex legislation and Treasury Regulations relating to the availability and calculation of depletion deductions by the unitholders. Further, because depletion is required to be computed separately by each unitholder and not by our partnership, no assurance can be given, and counsel is unable to express any opinion, with respect to the availability or extent of percentage depletion deductions to the unitholders for any taxable year. We encourage each prospective unitholder to consult his tax advisor to determine whether percentage depletion would be available to him.

Deductions for Intangible Drilling and Development Costs

We will elect to currently deduct intangible drilling and development costs (IDCs). IDCs generally include our expenses for wages, fuel, repairs, hauling, supplies, and other items that are incidental to, and necessary for, the drilling and preparation of wells for the production of oil, natural gas, or geothermal energy. The option to currently deduct IDCs applies only to those items that do not have a salvage value.

Although we will elect to currently deduct IDCs, each unitholder will have the option of either currently deducting IDCs or capitalizing all or part of the IDCs and amortizing them on a straight-line basis over a 60-month period, beginning with the taxable month in which the expenditure is made. If a unitholder makes the election to amortize the IDCs over a 60-month period, no IDC preference amount in respect of those IDCs will result for alternative minimum tax purposes.

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Integrated oil companies must capitalize 30% of all their IDCs (other than IDCs paid or incurred with respect to natural gas and oil wells located outside of the United States) and amortize these IDCs over 60 months beginning in the month in which those costs are paid or incurred. If the taxpayer ceases to be an integrated oil company, it must continue to amortize those costs as long as it continues to own the property to which the IDCs relate. An “integrated oil company” is a taxpayer that has economic interests in oil or natural gas properties and also carries on substantial retailing or refining operations. An oil or gas producer is deemed to be a substantial retailer or refiner if it is subject to the rules disqualifying retailers and refiners from taking percentage depletion. In order to qualify as an “independent producer” that is not subject to these IDC deduction limits, a unitholder, either directly or indirectly through certain related parties, may not be involved in the refining of more than 75,000 barrels of oil (or the equivalent amount of natural gas) on average for any day during the taxable year or in the retail marketing of natural gas and oil products exceeding $5 million per year in the aggregate.

IDCs previously deducted that are allocable to property (directly or through ownership of an interest in a partnership) and that would have been included in the adjusted tax basis of the property had the IDC deduction not been taken are recaptured to the extent of any gain realized upon the disposition of the property or upon the disposition by a unitholder of interests in us. Recapture is generally determined at the unitholder level. Where only a portion of the recapture property is sold, any IDCs related to the entire property are recaptured to the extent of the gain realized on the portion of the property sold. In the case of a disposition of an undivided interest in a property, a proportionate amount of the IDCs with respect to the property is treated as allocable to the transferred undivided interest to the extent of any gain recognized. See “ — Disposition of Units — Recognition of Taxable Gain or Loss.”

Deduction for U.S. Production Activities

Subject to the limitations on the deductibility of losses discussed above and the limitation discussed below, unitholders will be entitled to a deduction, herein referred to as the Section 199 deduction, equal to a specified percentage of our qualified production activities income that is allocated to such unitholder, but not to exceed 50% of unitholder’s IRS Form W-2 wages for the taxable year allocable to domestic production gross receipts. The percentages are 6% for qualified production activities income generated in the years 2007, 2008, and 2009; and 9% thereafter.

Qualified production activities income is generally equal to gross receipts from domestic production activities reduced by cost of goods sold allocable to those receipts, other expenses directly associated with those receipts, and a share of other deductions, expenses and losses that are not directly allocable to those receipts or another class of income. The products produced must be manufactured, produced, grown, or extracted in whole or in significant part by the taxpayer in the United States.

For a partnership, the Section 199 deduction is determined at the partner level. To determine his Section 199 deduction, each unitholder will aggregate his share of the qualified production activities income allocated to him from us with the unitholder’s qualified production activities income from other sources. Each unitholder must take into account his distributive share of the expenses allocated to him from our qualified production activities regardless of whether we otherwise have taxable income. However, our expenses that otherwise would be taken into account for purposes of computing the Section 199 deduction are taken into account only if and to the extent the unitholder’s share of losses and deductions from all of our activities is not disallowed by the tax basis rules, the at-risk rules or the passive activity loss rules. See “ — Tax Consequences of Unit Ownership — Limitations on Deductibility of Tax Losses.”

The amount of a unitholder’s Section 199 deduction for each year is limited to 50% of the IRS Form W-2 wages actually or deemed paid by the unitholder during the calendar year that are deducted in arriving at qualified production activities income. Each unitholder is treated as having been allocated IRS Form W-2 wages from us equal to the unitholder’s allocable share of our wages that are deducted in arriving at qualified production activities income for that taxable year. It is not anticipated that we or our subsidiaries will pay

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material wages that will be allocated to our unitholders, and thus a unitholder’s ability to claim the Section 199 deduction may be limited.

This discussion of the Section 199 deduction does not purport to be a complete analysis of the complex legislation and Treasury authority relating to the calculation of domestic production gross receipts, qualified production activities income, or IRS Form W-2 wages, or how such items are allocated by us to unitholders. Further, because the Section 199 deduction is required to be computed separately by each unitholder, no assurance can be given, and counsel is unable to express any opinion, as to the availability or extent of the Section 199 deduction to the unitholders. Each prospective unitholder is encouraged to consult his tax advisor to determine whether the Section 199 deduction would be available to him.

Potential Changes to Legislation. If enacted, proposed legislation being reviewed by Congress would deny certain oil and gas producers the ability to use the deduction currently offered under Code Section 199 for domestic production activities.

Lease Acquisition Costs. The cost of acquiring natural gas and oil leasehold or similar property interests is a capital expenditure that must be recovered through depletion deductions if the lease is productive. If a lease is proved worthless and abandoned, the cost of acquisition less any depletion claimed may be deducted as an ordinary loss in the year the lease becomes worthless. See “ — Depletion Deductions.”

Geophysical Costs. The cost of geophysical exploration incurred in connection with the exploration and development of oil and gas properties in the United States are deducted ratably over a 24-month period beginning on the date that such expense is paid or incurred.

Operating and Administrative Costs. Amounts paid for operating a producing well are deductible as ordinary business expenses, as are administrative costs to the extent they constitute ordinary and necessary business expenses that are reasonable in amount.

Tax Basis, Depreciation and Amortization

The tax basis of our tangible assets, such as casing, tubing, tanks, pumping units and other similar property, will be used for purposes of computing depreciation and cost recovery deductions and, ultimately, gain or loss on the disposition of these assets. The federal income tax burden associated with the difference between the fair market value of our assets and their tax basis immediately prior to (1) this offering will be borne by our general partner, and (2) any other offering will be borne by our unitholders as of that time. See “ — Tax Consequences of Unit Ownership — Allocation of Taxable Income, Gain, Loss and Deduction.”

To the extent allowable, we may elect to use the depreciation and cost recovery methods that will result in the largest deductions being taken in the early years after assets subject to these allowances are placed in service. If we determine not to adopt the remedial method of allocation with respect to any difference between the tax basis and the fair market value of goodwill immediately prior to this or any future offering, we may not be entitled to any amortization deductions with respect to any goodwill conveyed to us on formation or held by us at the time of any future offering. See “ — Uniformity of Units.” Property we subsequently acquire or construct may be depreciated using accelerated methods permitted by the Internal Revenue Code.

If we dispose of depreciable property by sale, foreclosure, or otherwise, all or a portion of any gain, determined by reference to the amount of depreciation previously deducted and the nature of the property, may be subject to the recapture rules and taxed as ordinary income rather than capital gain. Similarly, a unitholder who has taken cost recovery or depreciation deductions with respect to property we own will likely be required to recapture some or all of those deductions as ordinary income upon a sale of his interest in us. See “ — Tax Consequences of Unit Ownership — Allocation of Taxable Income, Gain, Loss and Deduction” and “ — Disposition of Units — Recognition of Taxable Gain or Loss.”

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The costs we incur in selling our units (called “syndication expenses”) must be capitalized and cannot be deducted currently, ratably, or upon our termination. There are uncertainties regarding the classification of costs as organization expenses, which we may be able to amortize, and as syndication expenses, which we may not amortize. The underwriting discounts and commissions we incur will be treated as syndication expenses.

Valuation and Tax Basis of Our Properties

The federal income tax consequences of the ownership and disposition of units will depend in part on our estimates of the relative fair market values and the initial tax bases of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we will make many of the relative fair market value estimates ourselves. These estimates and determinations of tax basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value or tax basis are later found to be incorrect, the character and amount of items of income, gain, loss, or deduction previously reported by unitholders might change, and unitholders might be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments.

Disposition of Units

Recognition of Taxable Gain or Loss

Gain or loss will be recognized on a sale of units equal to the difference between the unitholder’s amount realized and the unitholder’s tax basis for the units sold. A unitholder’s amount realized will equal the sum of the cash or the fair market value of other property he receives plus his share of our nonrecourse liabilities. Because the amount realized includes a unitholder’s share of our nonrecourse liabilities, the gain recognized on the sale of units could result in a tax liability in excess of any cash received from the sale.

Prior distributions from us in excess of cumulative net taxable income for a unit that decreased a unitholder’s tax basis in that unit will, in effect, become taxable income if the unit is sold at a price greater than the unitholder’s tax basis in that unit, even if the price received is less than his original cost.

Except as noted below, gain or loss recognized by a unitholder, other than a “dealer” in units, on the sale or exchange of a unit generally will be taxable as capital gain or loss. Capital gain recognized by an individual on the sale of units held more than one year is scheduled to be taxed at a maximum rate of 15% through December 31, 2010. However, a portion of this gain or loss, which may be substantial, will be separately computed and taxed as ordinary income or loss under Section 751 of the Internal Revenue Code to the extent attributable to assets giving rise to “unrealized receivables” or “inventory items” that we own. The term “unrealized receivables” includes potential recapture items, including depreciation, depletion, and IDC recapture. Ordinary income attributable to unrealized receivables and inventory items may exceed net taxable gain realized on the sale of a unit and may be recognized even if there is a net taxable loss realized on the sale of a unit. Thus, a unitholder may recognize both ordinary income and a capital loss upon a sale of units. Net capital loss may offset capital gains and no more than $3,000 of ordinary income, in the case of individuals, and may be used to offset only capital gains in the case of corporations.

The IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single tax basis for all those interests. Upon a sale or other disposition of less than all of those interests, a portion of that tax basis must be allocated to the interests sold using an “equitable apportionment” method, which generally means that the tax basis allocated to the interest sold equals an amount that bears the same relation to the partner’s tax basis in his entire interest in the partnership as the value of the interest sold bears to the value of the partner’s entire interest in the partnership. Treasury Regulations under Section 1223 of the Internal Revenue Code allow a selling unitholder who can identify units transferred with an ascertainable holding period to elect to use the actual holding period of the units transferred. Thus, according to the ruling, a unitholder will be unable to select high or low tax basis units to sell as would be

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the case with corporate stock, but, according to the regulations, may designate specific units sold for purposes of determining the holding period of units transferred. A unitholder electing to use the actual holding period of units transferred must consistently use that identification method for all subsequent sales or exchanges of units. A unitholder considering the purchase of additional units or a sale of units purchased in separate transactions is urged to consult his tax advisor as to the possible consequences of this ruling and those Treasury Regulations.

Specific provisions of the Internal Revenue Code affect the taxation of some financial products and securities, including partnership interests, by treating a taxpayer as having sold an “appreciated” partnership interest, i.e., one in which gain would be recognized if it were sold, assigned or terminated at its fair market value, if the taxpayer or related persons enter(s) into:

• a short sale;

• an offsetting notional principal contract; or

• a futures or forward contract with respect to the partnership interest or substantially identical property.

Moreover, if a taxpayer has previously entered into a short sale, an offsetting notional principal contract or a futures or forward contract with respect to the partnership interest, the taxpayer will be treated as having sold that position if the taxpayer or a related person then acquires the partnership interest or substantially identical property. The Secretary of the Treasury is also authorized to issue regulations that treat a taxpayer who enters into transactions or positions that have substantially the same effect as the preceding transactions as having constructively sold the financial position.

Tax Allocations Between Transferors and Transferees

In general, our taxable income or loss will be determined annually, will be prorated on a monthly basis and will be subsequently apportioned among the unitholders in proportion to the number of units owned by each of them as of the opening of the applicable exchange on the first business day of the month (the “Allocation Date”). However, gain or loss realized on a sale or other disposition of our assets other than in the ordinary course of business will be allocated among the unitholders on the Allocation Date in the month in which that gain or loss is recognized. As a result, a unitholder transferring units may be allocated income, gain, loss and deduction realized after the date of transfer.

Although simplifying conventions are contemplated by the Internal Revenue Code and most publicly traded partnerships use similar simplifying conventions, the use of this method may not be permitted under existing Treasury Regulations. Accordingly, Thompson & Knight LLP is unable to opine on the validity of this method of allocating income and deductions between transferor and transferee unitholders. If this method is not allowed under the Treasury Regulations, or applies to only transfers of less than all of the unitholder’s interest, our taxable income or losses might be reallocated among the unitholders. We are authorized to revise our method of allocation between unitholders, as well as among transferor and transferee unitholders whose interests vary during a taxable year, to conform to a method permitted under future Treasury Regulations.

A unitholder who owns units at any time during a quarter and who disposes of them prior to the record date set for a cash distribution for that quarter will be allocated items of our income, gain, loss, and deductions attributable to that quarter but will not be entitled to receive that cash distribution.

Notification Requirements

A unitholder who sells any of his units is generally required to notify us in writing of that sale within 30 days after the sale (or, if earlier, January 15 of the year following the sale). A person who purchases units from another unitholder also is generally required to notify us in writing of that purchase within 30 days after the purchase. Upon receiving such notifications, we are required to notify the IRS of that transaction and furnish

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specified information to the transferor and transferee. Failure to notify us of a purchase may, in some cases, lead to the imposition of penalties. However, these reporting requirements do not apply to a sale by an individual who is a citizen of the United States and who effects the sale or exchange through a broker who will satisfy such requirements.

Constructive Termination

We will be considered to have terminated for tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. A constructive termination results in the closing of our taxable year for all unitholders. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may result in more than 12 months of our taxable income or loss being includable in his taxable income for the year of termination. A constructive termination occurring on a date other than December 31 will result in our filing two tax returns (and unitholders’ receiving two Schedule K-1s) for one fiscal year and the cost of the preparation of these returns will be borne by all unitholders. We would be required to make new tax elections after a termination, including a new election under Section 754 of the Internal Revenue Code, and a termination would result in a deferral of our deductions for depreciation. A termination could also result in penalties if we were unable to determine that the termination had occurred. Moreover, a termination might either accelerate the application of, or subject us to, any tax legislation enacted before the termination.

Uniformity of Units

Because we cannot match transferors and transferees of units, we must maintain uniformity of the economic and tax characteristics of the units to a purchaser of these units. In maintaining uniformity, we may be unable to completely comply with a number of federal income tax requirements, both statutory and regulatory. Any non-uniformity could have a negative impact on the value of the units. The timing of deductions attributable to Section 743(b) adjustments to the common basis of our assets with respect to persons purchasing units after this offering may affect the uniformity of our units. See “ —Tax Consequences of Unit Ownership — Section 754 Election.” For example, a lack of uniformity can result from a literal application of certain Treasury Regulations. Any or all of these factors could cause the timing of a purchaser’s deductions to differ, depending on when the unit purchased was issued.

Our partnership agreement permits our general partner to take positions in filing our tax returns that preserve the uniformity of our units even under circumstances like those described above. These positions may include reducing for some unitholders the depletion, depreciation, amortization or loss deductions to which they would otherwise be entitled or reporting a slower amortization of section 743(b) adjustments for some unitholders than that to which they would otherwise be entitled. Our counsel, Thompson & Knight LLP, is unable to opine as to the validity of such filing positions. A unitholder’s basis in his or her units is reduced by his or her share of our deductions (whether or not such deductions were claimed on an individual income tax return) so that any position that we take that understates deductions will overstate the unitholder’s basis in his or her common units, which may cause the unitholder to understate gain or overstate loss on any sale of units. See “ —Disposition of Units — Recognition of Gain or Loss.” The IRS may challenge one or more of any positions we take to preserve the uniformity of units. If such a challenge were sustained, the uniformity of units might be affected, and, under some circumstances, the gain from the sale of units might be increased without the benefit of additional deductions.

Tax-Exempt Organizations and Other Investors

Ownership of units by employee benefit plans, other tax-exempt organizations, non-resident aliens, foreign corporations, and other non-U.S. persons raises issues unique to those investors and, as described below, may have substantially adverse tax consequences to them.

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Employee benefit plans and most other organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, are subject to federal income tax on unrelated business taxable income. Virtually all of our income allocated to a unitholder that is a tax-exempt organization will be unrelated business taxable income and will be taxable to them.

A regulated investment company, or “mutual fund,” is required to derive at least 90% of its gross income from certain permitted sources. Income from the ownership of units in a “qualified publicly traded partnership” is generally treated as income from a permitted source. We expect that we will meet the definition of a qualified publicly traded partnership.

Our partnership agreement generally prohibits non-resident aliens and foreign entities from owning our units. However, if non-resident aliens or foreign entities own our units, such non-resident aliens and foreign corporations, trusts, or estates that own units will be considered to be engaged in business in the United States because of the ownership of units. As a consequence they will be required to file federal tax returns to report their share of our income, gain, loss, or deduction and pay federal income tax at regular rates on their share of our net income or gain. Under rules applicable to publicly traded partnerships, we will withhold tax, at the highest effective applicable rate, from cash distributions made quarterly to foreign unitholders. Each foreign unitholder must obtain a taxpayer identification number from the IRS and submit that number to our transfer agent on a Form W-8 BEN or applicable substitute form in order to obtain credit for these withholding taxes. A change in applicable law may require us to change these procedures.

In addition, because a foreign corporation that owns units will be treated as engaged in a U.S. trade or business, that corporation may be subject to the U.S. branch profits tax at a rate of 30%, in addition to regular federal income tax, on its share of our income and gain, as adjusted for changes in the foreign corporation’s “U.S. net equity,” that is effectively connected with the conduct of a U.S. trade or business. That tax may be reduced or eliminated by an income tax treaty between the United States and the country in which the foreign corporate unitholder is a “qualified resident.” In addition, this type of unitholder is subject to special information reporting requirements under Section 6038C of the Internal Revenue Code.

Under a ruling issued by the IRS, a foreign unitholder who sells or otherwise disposes of a unit will be subject to federal income tax on gain realized on the sale or disposition of that unit to the extent the gain is effectively connected with a U.S. trade or business of the foreign unitholder. Because a foreign unitholder is considered to be engaged in business in the United States by virtue of the ownership of units, under this ruling a foreign unitholder who sells or otherwise disposes of a unit generally will be subject to federal income tax on gain realized on the sale or disposition of units. Apart from the ruling, a foreign unitholder would not be taxed or subject to withholding upon the sale or disposition of a unit if he has owned less than 5% in value of the units during the five-year period ending on the date of the disposition and if the units are regularly traded on an established securities market at the time of the sale or disposition.

Administrative Matters

Information Returns and Audit Procedures

We intend to furnish to each unitholder, within 90 days after the close of each calendar year, specific tax information, including a Schedule K-1, which describes his share of our income, gain, loss, and deduction for our preceding taxable year. In preparing this information, which will not be reviewed by counsel, we will take various accounting and reporting positions, some of which have been mentioned earlier, to determine each unitholder’s share of income, gain, loss, and deduction.

We cannot assure you that those positions will yield a result that conforms to the requirements of the Internal Revenue Code, Treasury Regulations or administrative interpretations of the IRS. Neither we nor Thompson & Knight LLP can assure prospective unitholders that the IRS will not successfully contend in court that those positions are impermissible. Any challenge by the IRS could negatively affect the value of the units.

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The IRS may audit our federal income tax information returns. Adjustments resulting from an IRS audit may require each unitholder to adjust a prior year’s tax liability and possibly may result in an audit of his own return. Any audit of a unitholder’s return could result in adjustments not related to our returns as well as those related to our returns.

Partnerships generally are treated as separate entities for purposes of federal tax audits, judicial review of administrative adjustments by the IRS and tax settlement proceedings. The tax treatment of partnership items of income, gain, loss, and deduction are determined in a partnership proceeding rather than in separate proceedings with the partners. The Internal Revenue Code requires that one partner be designated as the “Tax Matters Partner” for these purposes. The partnership agreement appoints the General Partner as our Tax Matters Partner.

The Tax Matters Partner will make some elections on our behalf and on behalf of unitholders. In addition, the Tax Matters Partner can extend the statute of limitations for assessment of tax deficiencies against unitholders for items in our returns. The Tax Matters Partner may bind a unitholder with less than a 1% profits interest in us to a settlement with the IRS unless that unitholder elects, by filing a statement with the IRS, not to give that authority to the Tax Matters Partner. The Tax Matters Partner may seek judicial review, by which all the unitholders are bound, of a final partnership administrative adjustment and, if the Tax Matters Partner fails to seek judicial review, judicial review may be sought by any unitholder having at least a 1% interest in profits or by any group of unitholders having in the aggregate at least a 5% interest in profits. However, only one action for judicial review will go forward, and each unitholder with an interest in the outcome may participate.

A unitholder must file a statement with the IRS identifying the treatment of any item on his federal income tax return that is not consistent with the treatment of the item on our return. Intentional or negligent disregard of this consistency requirement may subject a unitholder to substantial penalties.

Nominee Reporting

Persons who hold an interest in us as a nominee for another person are required to furnish to us:

• the name, address and taxpayer identification number of the beneficial owner and the nominee;

• a statement regarding whether the beneficial owner is:

a person that is not a U.S. person,

a foreign government, an international organization or any wholly owned agency or instrumentality of either of the foregoing, or

a tax-exempt entity;

• the amount and description of units held, acquired or transferred for the beneficial owner; and

• specific information including the dates of acquisitions and transfers, means of acquisitions and transfers, and acquisition cost for purchases, as well as the amount of net proceeds from sales.

Brokers and financial institutions are required to furnish additional information, including whether they are U.S. persons and specific information on units they acquire, hold or transfer for their own account. A penalty of $50 per failure, up to a maximum of $100,000 per calendar year, is imposed by the Internal Revenue Code for failure to report that information to us. The nominee is required to supply the beneficial owner of the units with the information furnished to us.

Accuracy-Related Penalties

An additional tax equal to 20% of the amount of any portion of an underpayment of tax that is attributable to one or more specified causes, including negligence or disregard of rules or regulations, substantial

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understatements of income tax and substantial valuation misstatements, is imposed by the Internal Revenue Code. No penalty will be imposed, however, for any portion of an underpayment if it is shown that there was a reasonable cause for that portion and that the taxpayer acted in good faith regarding that portion.

For individuals, a substantial understatement of income tax in any taxable year exists if the amount of the understatement exceeds the greater of 10% of the tax required to be shown on the return for the taxable year or $5,000. The amount of any understatement subject to penalty generally is reduced if any portion is attributable to a position adopted on the return:

• for which there is, or was, “substantial authority,” or

• as to which there is a reasonable basis and the relevant facts of that position are disclosed on the return.

If any item of income, gain, loss, or deduction included in the distributive shares of unitholders could result in that kind of an “understatement” of income for which no “substantial authority” exists, we would be required to disclose the pertinent facts on our return. In addition, we will make a reasonable effort to furnish sufficient information for unitholders to make adequate disclosure on their returns to avoid liability for this penalty. More stringent rules would apply to an understatement of tax resulting from ownership of units if we were classified as a “tax shelter.” We believe we will not be classified as a tax shelter.

A substantial valuation misstatement exists if the value of any property, or the tax basis of any property, claimed on a tax return is 150% or more of the amount determined to be the correct amount of the valuation or tax basis. No penalty is imposed unless the portion of the underpayment attributable to a substantial valuation misstatement exceeds $5,000 ($10,000 for a corporation other than an S corporation or a personal holding company). If the valuation claimed on a return is 200% or more than the correct valuation, the penalty imposed increases to 40%.

Reportable Transactions

If we were to engage in a “reportable transaction,” we (and possibly you and others) would be required to make a detailed disclosure of the transaction to the IRS. A transaction may be a reportable transaction based upon any of several factors, including the fact that it is a type of transaction publicly identified by the IRS as a “listed transaction” or that it produces certain kinds of losses for partnerships, individuals, S corporations, and trusts of at least $2 million in any single year, or $4 million in any combination of tax years. Our participation in a reportable transaction could increase the likelihood that our federal income tax information return (and possibly your tax return) is audited by the IRS. See “ — Information Returns and Audit Procedures” above.

Moreover, if we were to participate in a listed transaction or a reportable transaction (other than a listed transaction) with a significant purpose to avoid or evade tax, you could be subject to the following provisions of the American Jobs Creation Act of 2004:

• accuracy-related penalties with a broader scope, significantly narrower exceptions, and potentially greater amounts than described above at “ — Accuracy-Related Penalties,”

• for those persons otherwise entitled to deduct interest on federal tax deficiencies, nondeductibility of interest on any resulting tax liability, and

• in the case of a listed transaction, an extended statute of limitations.

We do not expect to engage in any reportable transactions.

State, Local and Other Tax Considerations

In addition to federal income taxes, you likely will be subject to other taxes, such as state, local and foreign income taxes, unincorporated business taxes and estate, inheritance or intangible taxes that may be imposed by

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the various jurisdictions in which we do business or own property now or in the future or in which you are a resident. Although an analysis of those various taxes is not presented here, each prospective unitholder should consider their potential impact on his investment in us. We initially will own property or do business in Texas, New Mexico and Oklahoma. New Mexico and Oklahoma currently impose a personal income tax. We may also own property or do business in other jurisdictions in the future that impose personal income taxes or that impose entity level taxes to which we could be subject. Although you may not be required to file a return and pay taxes in some jurisdictions if your income from those jurisdictions falls below the filing and payment requirements, you will be required to file income tax returns and to pay income taxes in many of the jurisdictions in which we do business or own property and may be subject to penalties for failure to comply with those requirements. In some jurisdictions, tax losses may not produce a tax benefit in the year incurred and may not be available to offset income in subsequent taxable years. Some of the jurisdictions may require us, or we may elect, to withhold a percentage of income from amounts to be distributed to a unitholder who is not a resident of the jurisdiction. Withholding, the amount of which may be greater or less than a particular unitholder’s income tax liability to the jurisdiction, generally does not relieve a nonresident unitholder from the obligation to file an income tax return. Amounts withheld will be treated as if distributed to unitholders for purposes of determining the amounts distributed by us. See “ — Tax Consequences of Unit Ownership — Entity-Level Collections.” Based on current law and our estimate of our future operations, our general partner anticipates that any amounts required to be withheld will not be material.

It is the responsibility of each unitholder to investigate the legal and tax consequences, under the laws of pertinent jurisdictions, of his investment in us. Accordingly, each prospective unitholder is urged to consult, and depend upon, his tax counsel or other advisor with regard to those matters. Further, it is the responsibility of each unitholder to file all state, local and foreign, as well as United States federal tax returns, that may be required of him. Thompson & Knight LLP has not rendered an opinion on the state, local or foreign tax consequences of an investment in us.

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INVESTMENT IN US BY EMPLOYEE BENEFIT PLANS

An investment in us by an employee benefit plan is subject to additional considerations because the investments of these plans are subject to the fiduciary responsibility and prohibited transaction provisions of ERISA and restrictions imposed by Section 4975 of the Internal Revenue Code. For these purposes the term “employee benefit plan” includes, but is not limited to, qualified pension, profit-sharing and stock bonus plans, Keogh plans, simplified employee pension plans and tax deferred annuities or IRAs established or maintained by an employer or employee organization. Among other things, consideration should be given to:

• whether the investment is prudent under Section 404(a)(1)(B) of ERISA;

• whether in making the investment, that plan will satisfy the diversification requirements of Section 404(a)(1)(C) of ERISA; and

• whether the investment will result in recognition of unrelated business taxable income by the plan and, if so, the potential after-tax investment return. See “Material Tax Consequences — Tax-Exempt Organizations and Other Investors.”

The person with investment discretion with respect to the assets of an employee benefit plan, often called a fiduciary, should determine whether an investment in us is authorized by the appropriate governing instrument and is a proper investment for the plan.

Section 406 of ERISA and Section 4975 of the Internal Revenue Code prohibit employee benefit plans, and also IRAs that are not considered part of an employee benefit plan, from engaging in specified transactions involving “plan assets” with parties that are “parties in interest” under ERISA or “disqualified persons” under the Internal Revenue Code with respect to the plan.

In addition to considering whether the purchase of common units is a prohibited transaction, a fiduciary of an employee benefit plan should consider whether the plan will, by investing in us, be deemed to own an undivided interest in our assets, with the result that our operations would be subject to the regulatory restrictions of ERISA, including its prohibited transaction rules, as well as the prohibited transaction rules of the Internal Revenue Code.

The Department of Labor regulations provide guidance with respect to whether the assets of an entity in which employee benefit plans acquire equity interests would be deemed “plan assets” under some circumstances. Under these regulations, an entity’s assets would not be considered to be “plan assets” if, among other things:

(a) the equity interests acquired by employee benefit plans are publicly offered securities — i.e., the equity interests are widely held by 100 or more investors independent of the issuer and each other, freely transferable and registered under some provisions of the federal securities laws;

(b) the entity is an “operating company,” — i.e., it is primarily engaged in the production or sale of a product or service other than the investment of capital either directly or through a majority-owned subsidiary or subsidiaries; or

(c) there is no significant investment by benefit plan investors, which is defined to mean that less than 25% of the value of each class of equity interest is held by the employee benefit plans referred to above, IRAs and other employee benefit plans not subject to ERISA, including governmental plans.

Our assets should not be considered “plan assets” under these regulations because it is expected that the investment will satisfy the requirements in (a) above.

Plan fiduciaries contemplating a purchase of common units should consult with their own counsel regarding the consequences under ERISA and the Internal Revenue Code in light of the serious penalties imposed on persons who engage in prohibited transactions or other violations.

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UNDERWRITING

Lehman Brothers Inc. and Wachovia Capital Markets, LLC are acting as the representatives of the underwriters and the joint book-running managers of this offering. Under the terms of an underwriting agreement, which will be filed as an exhibit to the registration statement, each of the underwriters named below has severally agreed to purchase from us the number of common units shown opposite its name below:

Underwriters	Number of Common Units
Lehman Brothers Inc.
Wachovia Capital Markets, LLC
Total	9,250,000

The underwriting agreement provides that the underwriters’ obligation to purchase common units depends on the satisfaction of the conditions contained in the underwriting agreement including:

• the obligation to purchase common units offered hereby (other than those common units covered by their option to purchase additional common units as described below), if any of the common units are purchased;

• the representations and warranties made by us to the underwriters are true;

• there is no material change in our business or the financial markets; and

• we deliver customary closing documents to the underwriters.

Commissions and Expenses

The following table summarizes the underwriting discounts and commissions (including a structuring fee) we will pay to the underwriters. These amounts are shown assuming both no exercise and full exercise of the underwriters’ option to purchase additional common units. The underwriting fee is the difference between the initial price to the public and the amount the underwriters pay to us for the common units.

	No Exercise	Full Exercise
Per Unit	$	$
Total	$	$

The representatives of the underwriters have advised us that the underwriters propose to offer the common units directly to the public at the public offering price on the cover of this prospectus and to selected dealers, which may include the underwriters, at such offering price less a selling concession not in excess of $             per unit. After the offering, the representatives may change the offering price and other selling terms.

The expenses of the offering that are payable by us are estimated to be $2.3 million (excluding underwriting discounts and commissions and the structuring fee).

Option to Purchase Additional Common Units

We have granted the underwriters an option exercisable for 30 days after the date of this prospectus, to purchase, from time to time, in whole or in part, up to an aggregate of 1,387,500 common units at the public offering price less underwriting discounts and commissions. This option may be exercised if the underwriters sell more than 9,250,000 common units in connection with this offering. To the extent that this option is exercised, each underwriter will be obligated, subject to certain conditions, to purchase its pro rata portion of these additional common units based on the underwriter’s underwriting commitment in the offering as indicated in the table at the beginning of this Underwriting section.

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Lock-Up Agreements

We, our affiliates that own common units, and the directors and executive officers of HK Management have agreed that, without the prior written consent of each of Lehman Brothers Inc. and Wachovia Capital Markets, LLC, we and they will not directly or indirectly, (1) offer for sale, sell, pledge, or otherwise dispose of (or enter into any transaction or device that is designed to, or could be expected to, result in the disposition by any person at any time in the future of) any common units (including, without limitation, common units that may be deemed to be beneficially owned by us or them in accordance with the rules and regulations of the Securities and Exchange Commission and common units that may be issued upon exercise of any options or warrants) or securities convertible into or exercisable or exchangeable for common units, (2) enter into any swap or other derivatives transaction that transfers to another, in whole or in part, any of the economic consequences of ownership of the common units, (3) make any demand for or exercise any right or file or cause to be filed a registration statement, including any amendments thereto, with respect to the registration of any common units or securities convertible, exercisable or exchangeable into common units or any of our other securities, or (4) publicly disclose the intention to do any of the foregoing for a period of 180 days after the date of this prospectus.

The 180-day restricted period described in the preceding paragraph will be extended if:

• during the last 17 days of the 180-day restricted period we issue an earnings release or material news or a material event relating to us occurs; or

• prior to the expiration of the 180-day restricted period, we announce that we will release earnings results during the 16-day period beginning on the last day of the 180-day period,

in which case the restrictions described in the preceding paragraph will continue to apply until the expiration of the 18-day period beginning on the issuance of the earnings release or the announcement of the material news or occurrence of a material event, unless such extension is waived in writing by Lehman Brothers Inc. and Wachovia Capital Markets, LLC.

Lehman Brothers Inc. and Wachovia Capital Markets, LLC, in their sole discretion, may release the common units and other securities subject to the lock-up agreements described above in whole or in part at any time with or without notice. When determining whether or not to release common units and other securities from lock-up agreements, Lehman Brothers Inc. and Wachovia Capital Markets, LLC will consider, among other factors, the holder’s reasons for requesting the release, the number of common units and other securities for which the release is being requested and market conditions at the time.

As described below under “— Directed Unit Program,” any participants in the Directed Unit Program shall be subject to a 180-day lock up with respect to any units sold to them pursuant to that program. This lock up will have similar restrictions and an identical extension provision as the lock-up agreement described above. Any units sold in the Directed Unit Program to HK Management’s directors or executive officers shall be subject to the lock-up agreement described above.

Offering Price Determination

Prior to this offering, there has been no public market for our common units. The initial public offering price will be negotiated between the representatives and us. In determining the initial public offering price of our common units, the representatives will consider:

• the history and prospects for the industry in which we compete;

• our financial information;

• the ability of our management and our business potential and earning prospects;

172

• the prevailing securities markets at the time of this offering; and

• the recent market prices of, and the demand for, publicly traded common units of generally comparable companies.

Indemnification

We have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act and liabilities incurred in connection with the Directed Unit Program referred to below, and to contribute to payments that the underwriters may be required to make for these liabilities.

Directed Unit Program

At our request, the underwriters have reserved for sale at the initial public offering price up to 5% of the common units offered hereby for officers, directors, employees and certain other persons associated with us. The number of common units available for sale to the general public will be reduced to the extent such persons purchase such reserved common units. Any reserved common units not so purchased will be offered by the underwriters to the general public on the same basis as the other common units offered hereby. Any participants in this program shall be prohibited from selling, pledging or assigning any common units sold to them pursuant to this program for a period of 180 days after the date of this prospectus. This 180-day lock up period shall be extended with respect to our issuance of an earnings release or if a material news or a material event relating to us occurs, in the same manner as described above under “ — Lock-Up Agreements.”

Stabilization, Short Positions and Penalty Bids

The representatives may engage in stabilizing transactions, short sales and purchases to cover positions created by short sales, and penalty bids or purchases for the purpose of pegging, fixing or maintaining the price of the common units, in accordance with Regulation M under the Securities Exchange Act of 1934:

• Stabilizing transactions permit bids to purchase the underlying security so long as the stabilizing bids do not exceed a specified maximum.

• A short position involves a sale by the underwriters of shares in excess of the number of units the underwriters are obligated to purchase in the offering, which creates the syndicate short position. This short position may be either a covered short position or a naked short position. In a covered short position, the number of units involved in the sales made by the underwriters in excess of the number of units they are obligated to purchase is not greater than the number of units that they may purchase by exercising their option to purchase additional units. In a naked short position, the number of units involved is greater than the number of units in their option to purchase additional units. The underwriters may close out any short position by either exercising their option to purchase additional units and/or purchasing units in the open market. In determining the source of units to close out the short position, the underwriters will consider, among other things, the price of units available for purchase in the open market as compared to the price at which they may purchase units through their option to purchase additional units. A naked short position is more likely to be created if the underwriters are concerned that there could be downward pressure on the price of the units in the open market after pricing that could adversely affect investors who purchase in the offering.

• Syndicate covering transactions involve purchases of the common units in the open market after the distribution has been completed in order to cover syndicate short positions.

• Penalty bids permit the representatives to reclaim a selling concession from a syndicate member when the common units originally sold by the syndicate member is purchased in a stabilizing or syndicate covering transaction to cover syndicate short positions.

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These stabilizing transactions, syndicate covering transactions and penalty bids may have the effect of raising or maintaining the market price of our common units or preventing or retarding a decline in the market price of the common units. As a result, the price of the common units may be higher than the price that might otherwise exist in the open market. These transactions may be effected on The New York Stock Exchange or otherwise and, if commenced, may be discontinued at any time.

Neither we nor any of the underwriters makes any representation or prediction as to the direction or magnitude of any effect that the transactions described above may have on the price of the common units. In addition, neither we nor any of the underwriters makes representation that the representatives will engage in these stabilizing transactions or that any transaction, once commenced, will not be discontinued without notice.

Electronic Distribution

A prospectus in electronic format may be made available on the Internet sites or through other online services maintained by one or more of the underwriters and/or selling group members participating in this offering, or by their affiliates. In those cases, prospective investors may view offering terms online and, depending upon the particular underwriter or selling group member, prospective investors may be allowed to place orders online. The underwriters may agree with us to allocate a specific number of common units for sale to online brokerage account holders. Any such allocation for online distributions will be made by the representatives on the same basis as other allocations.

Other than the prospectus in electronic format, the information on any underwriter’s or selling group member’s web site and any information contained in any other web site maintained by an underwriter or selling group member is not part of the prospectus or the registration statement of which this prospectus forms a part, has not been approved and/or endorsed by us or any underwriter or selling group member in its capacity as underwriter or selling group member and should not be relied upon by investors.

The New York Stock Exchange

We intend to apply to list our common units for quotation on The New York Stock Exchange under the symbol “HKE.” In connection with that listing, the underwriters have undertaken to sell the minimum number of common units to the minimum number of beneficial owners necessary to meet The New York Stock Exchange listing requirements.

Discretionary Sales

The underwriters have informed us that they do not intend to confirm sales to discretionary accounts that exceed 5% of the total number of common units offered by them.

Relationships/NASD Conduct Rules

The underwriters may in the future perform investment banking and advisory services for us from time to time for which they may in the future receive customary fees and expenses.

Because the Financial Industry Regulatory Authority, or the FINRA (formerly known as the National Association of Securities Dealers, Inc., or the NASD), views the common units offered hereby as interests in a direct participation program, the offering is being made in compliance with Rule 2810 of the NASD’s Conduct Rules (which are part of the FINRA rules). Investor suitability with respect to the common units should be judged similarly to the suitability with respect to other securities that are listed for trading on a national securities exchange.

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VALIDITY OF THE COMMON UNITS

The validity of the common units will be passed upon for us by Thompson & Knight LLP, Houston, Texas. Certain legal matters in connection with the common units offered hereby will be passed upon for the underwriters by Vinson & Elkins L.L.P., Houston, Texas.

EXPERTS

The combined financial statements of the HK Energy Partners Predecessor LP as of December 31, 2006 and 2005 (successor) and for the year ended December 31, 2006 (successor), the period from July 28, 2005 to December 31, 2005 (successor), the period from January 1, 2005 to July 27, 2005 (predecessor), and the year ended December 31, 2004 (predecessor) included in this prospectus have been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report appearing herein, and have been so included in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.

The statements of revenues less direct operating expenses – assets acquired from KCS Energy, Inc. for the period from January 1, 2006 to July 11, 2006 and the years ended December 31, 2005 and 2004, included in this prospectus have been audited by Deloitte & Touche LLP, an independent registered public accounting firm as stated in its report appearing herein, and have been included in reliance upon the report of such firm given its authority as experts in accounting and auditing.

The balance sheet of HK Energy Partners GP LP as of October 24, 2007 included in this prospectus has been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in its report appearing herein, and has been included in reliance upon the report of such firm given upon its authority as experts in accounting and auditing.

The balance sheet of HK Energy Partners LP as of October 24, 2007 included in this prospectus has been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in its report appearing herein, and has been included in reliance upon the report of such firm given upon its authority as experts in accounting and auditing.

The information appearing in this prospectus concerning estimates of our oil and gas proved reserves as of December 31, 2006 and June 30, 2007 was prepared by Netherland, Sewell & Associates, Inc., an independent engineering firm with respect to the partnership properties, and has been included herein upon the authority of this firm as an expert.

WHERE YOU CAN FIND MORE INFORMATION

We have filed with the SEC a registration statement on Form S-1 regarding the common units. This prospectus does not contain all of the information found in the registration statement. For further information regarding us and the common units offered by this prospectus, you may desire to review the full registration statement, including its exhibits and schedules, filed under the Securities Act. The registration statement of which this prospectus forms a part, including its exhibits and schedules, may be inspected and copied at the public reference room maintained by the SEC at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. Copies of the materials may also be obtained from the SEC at prescribed rates by writing to the public reference room maintained by the SEC at 100 F Street, N.E., Room 1580, 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. The SEC maintains a web site on the Internet athttp://www.sec.gov. Our registration statement, of which this prospectus constitutes a part, can be downloaded from the SEC’s web site.

We intend to furnish our unitholders annual reports containing our audited financial statements and furnish or make available quarterly reports containing our unaudited interim financial information for the first three fiscal quarters of each of our fiscal years.

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INDEX TOFINANCIAL STATEMENTS

	Page
HK ENERGY PARTNERS LP
Unaudited Pro Forma Combined Financial Statements Basis of Presentation	F-2
Unaudited Pro Forma Combined Balance Sheet as of June 30, 2007	F-3
Unaudited Pro Forma Combined Statement of Operations for the six months ended June 30, 2007	F-4
Unaudited Pro Forma Combined Statement of Operations for the year ended December 31, 2006	F-5
Notes to Unaudited Pro Forma Combined Financial Statements	F-6
Pro Forma Combined Supplemental Oil and Gas Information (Unaudited)	F-9
HK ENERGY PARTNERS LP PREDECESSOR
Report of Independent Registered Public Accounting Firm	F-12
Combined Balance Sheets as of December 31, 2006 and 2005	F-13
Combined Statements of Operations for the year ended December 31, 2006, the period from July 28, 2005 to December 31, 2005, the period from January 1, 2005 to July 27, 2005 and the year ended December 31, 2004	F-14
Combined Statement of Changes in Owner’s Equity for the year ended December 31, 2006, the period from July 28, 2005 to December 31, 2005, the period from January 1, 2005 to July 27, 2005 and the year ended December 31, 2004	F-15
Combined Statement of Cash Flows for the year ended December 31, 2006, the period from July 28, 2005 to December 31, 2005, the period from January 1, 2005 to July 27, 2005 and the year ended December 31, 2004	F-16
Notes to the Combined Financial Statements	F-17
Supplemental Oil and Gas Information (Unaudited)	F-29
HK ENERGY PARTNERS LP PREDECESSOR
Condensed Combined Balance Sheets as of June 30, 2007 and December 31, 2006 (unaudited)	F-33
Condensed Combined Statements of Operations for the six months ended June 30, 2007 and 2006 (unaudited)	F-34
Condensed Combined Statements of Cash Flows for the six months ended June 30, 2007 and 2006 (unaudited)	F-35
Notes to the Condensed Combined Financial Statements (Unaudited)	F-36
KCS PROPERTIES
Report of Independent Registered Public Accounting Firm	F-47
Statements of Revenues Less Direct Operating Expenses — Assets Acquired from KCS Energy, Inc. for period from January 1, 2006 to July 11, 2006 and the years ended December 31, 2005 and 2004	F-48
Notes to Statements of Revenues Less Direct Operating Expenses	F-49
Supplemental Oil and Gas Information (Unaudited)	F-50
HK ENERGY PARTNERS LP
Report of Independent Registered Public Accounting Firm	F-53
Balance Sheet as of October 24, 2007	F-54
Note to Balance Sheet	F-55
HK ENERGY PARTNERS GP LP
Report of Independent Registered Public Accounting Firm	F-56
Balance Sheet as of October 24, 2007	F-57
Note to Balance Sheet	F-58

F-1

HK ENERGY PARTNERS LP

UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS

BASIS OF PRESENTATION

The following unaudited pro forma combined financial statements give effect to the formation of HK Energy Partners LP (the “Partnership”), the contribution to the Partnership by affiliates of Petrohawk of all of the oil and natural gas properties (the “Partnership Properties”) of HK Energy Partners LP Predecessor (the “Predecessor”), and the other transactions described in Note 2 to these unaudited pro forma financial statements (collectively, the “Formation Transactions”).

The unaudited pro forma combined balance sheet gives effect to the Formation Transactions as if they had occurred on June 30, 2007. The unaudited pro forma combined statements of operations give effect to the Formation Transactions as if they had occurred on January 1, 2006. In addition, with respect to the oil and natural gas properties included within the Partnership Properties that were originally acquired by Petrohawk as part of its merger with KCS Energy, Inc., on July 12, 2006 (the “KCS Properties”), the unaudited pro forma combined statements of operations give effect to such acquisition as though it had occurred on January 1, 2006.

The unaudited pro forma combined financial statements of HK Energy Partners LP are based on the historical combined financial statements of HK Energy Partners LP Predecessor and the historical statements of revenues less direct operating expenses of the KCS Properties included elsewhere in this prospectus. The Partnership Properties comprising HK Energy Partners LP Predecessor are owned, controlled and managed by subsidiaries of Petrohawk, and the unaudited pro forma combined financial statements have been prepared based upon a carryover basis of historical cost of the Partnership Properties as opposed to recognition at fair value under the purchase method of accounting.

The unaudited pro forma combined financial statements should be read in conjunction with the audited financial statements of HK Energy Partners LP Predecessor and the audited statements of revenues less direct operating expenses of the KCS Properties and the notes to such financial statements included elsewhere in this prospectus. The unaudited pro forma combined financial statements should not be construed to be indicative of future results or results that actually would have occurred if the acquisition of the KCS Properties and the Formation Transactions had occurred at the dates presented.

F-2

HK ENERGY PARTNERS LP

UNAUDITED PRO FORMA COMBINED BALANCE SHEET

	June 30, 2007
	Historical			Adjustments			Pro Forma
	(In thousands)
ASSETS
Current assets:
Cash	$	—		$	58,120	(4)	$	5,000
					415,179	(2)
					(15,000	)(2)
					(750	)(3)
					(165,000	)(6)
					(287,549	)(1)
Accounts receivable		6,711			—			6,711
Marketable securities		—			165,000	(6)		165,000
Total current assets		6,711			170,000			176,711
Oil and gas properties(full cost method):
Evaluated		435,226			—			435,226
Unevaluated		112,575			—			112,575
Gross oil and gas properties		547,801			—			547,801
Less — accumulated depletion		(111,881	)		—			(111,881	)
Net oil and gas properties		435,920			—			435,920
Other noncurrent assets:
Goodwill		153,559			—			153,559
Debt issuance costs, net of amortization		2,285			(2,285	)(1)		750
					750	(3)
Total assets	$	598,475		$	168,465		$	766,940
LIABILITIES AND OWNERS' EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	3,955		$	1,009	(5)	$	4,964
Total current liabilities		3,955			1,009			4,964
Long-term debt		269,625			(269,625	)(1)		223,120
					58,120	(4)
					165,000	(6)
Asset retirement obligations		6,579			—			6,579
Deferred income taxes		764			—			764
Commitments and contingencies
Owner's equity
General partner units		—			8,304	(2)		8,304
Subordinated units		—			103,795	(2)		103,795
Common units		—			303,081	(2)		287,072
					(15,000	)(2)
					(1,009	)(5)
Owner’s net equity		317,552			(249,934	)(1)		132,342
					(67,618	)(1)
					(165,000	)(6)
					297,342	(1)
Total owner's equity		317,552			213,961			531,513
Total liabilities and owner's equity	$	598,475		$	168,465		$	766,940

See notes to the unaudited pro forma combined financial statements.

F-3

HK ENERGY PARTNERS LP

UNAUDITED PRO FORMA COMBINED STATEMENT OF OPERATIONS

	Six Months Ended June 30, 2007
	Historical			Adjustments			Pro Forma
	(in thousands, except per unit amounts)
Operating revenues:
Oil and gas	$	37,272		$	—		$	37,272
Operating expenses:
Production:
Lease operating		5,536			—			5,536
Workover and other		38			—			38
Taxes other than income		3,664			—			3,664
Gathering, transportation and other		824			—			824
General and administrative		2,873			(2,873	)(9)		2,861
					2,861	(9)
Depletion, depreciation and amortization		13,034			—			13,034
Total operating expenses		25,969			(12	)		25,957
Income from operations		11,303			12			11,315
Interest expense and other		(11,882	)		11,882	(7)		(2,521	)
					(2,521	)(7)
Net (loss) income before income taxes	$	(579	)	$	9,373		$	8,794
Income tax provision		(50	)		—			(50	)
Net (loss) income	$	(629	)	$	9,373		$	8,744
General partner’s interest in net income							$	175
Limited partners’ interest in net income							$	8,569
Net income per limited partner units:
Common units (basic and diluted)							$	0.57
Weighted average limited partner units outstanding (basic and diluted):
Common units								15,154
Subordinated units								5,190

See notes to the unaudited pro forma combined financial statements.

F-4

HK ENERGY PARTNERS LP

UNAUDITED PRO FORMA COMBINED STATEMENT OF OPERATIONS

	Year Ended December 31, 2006
	Historical			Acquisition			Combined			Adjustments			Pro Forma
	(in thousands, except per share amounts)
Operating revenues:
Oil and gas	$	59,578		$	18,707	(8)		78,285			—		$	78,285
Operating expenses:
Production:
Lease operating		8,694			1,634	(8)		10,328			—			10,328
Workover and other		198			49	(8)		247			—			247
Taxes other than income		5,606			1,861	(8)		7,467			—			7,467
Gathering, transportation and other		878			605	(8)		1,483			—			1,483
Impairment expense		53,190			—			53,190			—			53,190
General and administrative		4,683			—			4,683			(4,683	)(9)		5,723
											5,723	(9)
Depletion, depreciation and amortization		23,740			—			23,740			(23,740	)(10)		30,617
											30,617	(10)
Total operating expenses		96,989			4,149			101,138			7,917			109,055
(Loss) Income from operations		(37,411	)		14,558			(22,853	)		(7,917	)		(30,770	)
Interest expense and other		(18,953	)		—			(18,953	)		18,953	(7)		(5,042	)
											(5,042	)(7)
Net (loss) income before income taxes	$	(56,364	)	$	14,558		$	(41,806	)	$	5,994		$	(35,812	)
Income tax provision		(714	)		—			(714	)		—			(714	)
Net (loss) income	$	(57,078	)	$	14,558		$	(42,520	)	$	5,994		$	(36,526	)
General partner’s interest in net loss													$	(731	)
Limited partners’ interest in net loss													$	(35,795	)
Net loss per limited partner units:
Common units basic and diluted													$	(2.36	)
Weighted average limited partner units outstanding (basic and diluted):
Common units														15,154
Subordinated units														5,190

See notes to the unaudited pro forma combined financial statements.

F-5

HK ENERGY PARTNERS LP

NOTES TO UNAUDITED PRO FORMA

COMBINED FINANCIAL STATEMENTS

1. General

HK Energy Partners LP (the “Partnership”) is a Delaware limited partnership formed in October 2007 by Petrohawk Energy Corporation (“Petrohawk”) to acquire, develop, exploit and produce oil and natural gas properties. The Partnership intends to consummate the initial public offering of its common units representing limited partnership interests (the “offering”) as described in this prospectus and to conclude the Formation Transactions described in Note 2, below, in conjunction with the closing of the offering. The Partnership has conducted no operations to date.

As part of the Formation Transactions, the Partnership will acquire all of the oil and natural gas properties (the “Partnership Properties”) comprising HK Energy Partners LP Predecessor (the “Predecessor” or the “Company”). The historical financial statements of the Partnership have been derived from the combined financial statements of the Predecessor included elsewhere in this prospectus. The historical financial statements of the Predecessor represent a “carve-out” of the Partnership Properties from the consolidated financial statements of Mission Resources Corporation (“Mission”) for the period from January 1, 2004 through July 27, 2005 and from the consolidated financial statements of Petrohawk for the period from July 28, 2005 through June 30, 2007. See Note 1 to the audited combined financial statements of HK Energy Partners LP Predecessor for additional information regarding the basis of preparation of such financial statements.

The pro forma combined statements of operations give effect to the July 12, 2006 acquisition by the Predecessor of certain properties of KCS Energy, Inc. (the “KCS Properties”) as though such acquisition had occurred on January 1, 2006. See Note 1 to the audited combined financial statements of HK Energy Partners LP Predecessor for additional information regarding the accounting for the acquisition of the KCS Properties by the Predecessor.

2. Formation Transactions

In conjunction with the closing of the offering, the Partnership will engage in the transactions described below (the “Formation Transactions”). In the Formation Transactions, the Partnership will:

(i) receive the Partnership Properties, consisting of 107 Bcfe of estimated proved oil and natural gas reserves located in the Permian basin that have been carved-out of the 209 Bcfe of estimated proved reserves acquired by Petrohawk in its merger with Mission in July 2005 and 38 Bcfe of estimated proved oil and natural gas reserves located in the Permian basin that have been carved-out of the 428 Bcfe of estimated proved reserves acquired by Petrohawk in its merger with KCS Energy, Inc., in July 2006.

(ii) issue 5,904,048 common units and 5,189,742 subordinated units, representing an aggregate 53.4% limited partner interest in us to a subsidiary of Petrohawk;

(iii) issue 9,250,000 common units to the public, representing a 44.6% limited partner interest in us in exchange for estimated net offering proceeds of $165.0 million;

(iv) issue a 2% general partner interest in us and all of our incentive distribution rights to HK Energy Partners GP LP, our general partner;

(v) utilize the estimated net proceeds of the offering to purchase qualifying investment grade securities and pledge them as collateral under its credit facility;

(vi) borrow an estimated $165.0 million in term debt and $58.1 million in revolving debt under its credit facility and distribute the proceeds of these borrowings to its general partner; and

F-6

(vii) enter into the administrative services agreement with Petrohawk, HK Management and HK Energy Partners GP LP pursuant to which the Partnership will reimburse Petrohawk for certain operating expenses and for providing various general and administrative services to the Partnership and its affiliates.

3. Pro Forma Adjustments

The unaudited pro forma combined balance sheet includes the following adjustments:

(1) These adjustments reflect the elimination of the certain components of HK Energy Partners LP Predecessor’s historical owners’ equity, affiliated receivables and payables, long-term debt and other assets and liabilities as of June 30, 2007.

(2) Reflects the receipt of cash proceeds of $185.0 million from the issuance of 9,250,000 common units by the Partnership, including estimated offering costs of $15.0 million (based on an assumed initial public offering price of $20.00 per common unit). Offering costs primarily consist of accounting fees, legal fees, printing expenses, underwriting discounts and commissions and a structuring fee.

(3) To record estimated debt issuance costs incurred in conjunction with the closing of the Partnership’s new credit facility.

(4) Reflects estimated borrowings of $58.1 million under the revolving portion of the Partnership’s new credit facility which will be distributed to its general partner and another subsidiary of Petrohawk.

(5) Reflects the reimbursement of certain third party of costs incurred on behalf of the Partnership in connection with the issuance of 9,250,000 common units by the Partnership.

(6) Reflects the purchase of qualifying investment grade securities utilizing the estimated net proceeds from this offering and borrowings of $165.0 million under the term portion of our new credit facility. These debt proceeds will be distributed to our general partner and another subsidiary of Petrohawk. The qualifying investment grade securities will be pledged as collateral to secure indebtedness under the credit facility.

The unaudited pro forma combined statements of operations include the following adjustments:

(7) This adjustment decreases interest expense for the effect of the elimination of a portion of the Partnership’s indebtedness historically allocated long-term debt balances and the recording of the Partnership’s estimated borrowings of $58.1 million under the revolving portion of the new credit facility, estimated borrowings of $165.0 million under the term portion of the credit facility, estimated purchase of $165.0 million of marketable securities and amortization expense associated with projected debt issuance costs. The interest rate used in the calculation of interest expense (7.5% for the revolving debt facility, 5.8% on the term debt and 5.5% on the marketable securities) is based on expected actual interest rates. The life used in the calculation of amortization expense is based on the expected life of each instrument. A one percentage point change in the interest rate would result in an adjustment to pro forma interest expense of $0.3 million and $0.6 million for the six months ended June 30, 2007 and year ended December 31, 2006, respectively.

(8) Reflects revenues and direct operating expenses generated from the KCS Properties prior to the date of acquisition by the Partnership on July 12, 2006 derived from the audited Statements of Revenues Less Direct Operating Expenses — Assets Acquired from KCS Energy, Inc.

(9) To adjust historical general and administrative expense to reflect the administrative services agreement with Petrohawk, HK management and HK Energy Partners GP LP as well as certain net additional costs expected to be incurred on an ongoing basis.

F-7

(10) To adjust historical depletion expense associated with oil and gas properties to reflect the acquisition of the KCS Properties by the Partnership as if the acquisition had occurred on January 1, 2006. Depletion expense is calculated using the unit of production method under full cost accounting.

4. Income Taxes

No provision for income taxes is made in our combined financial statements because the taxable income or loss of the Partnership will be included in the income tax returns of the individual partners with the exception of the Texas Franchise tax.

A reconciliation between the statutory federal income tax rate and the Partnership’s pro forma effective income tax rate as if the Partnership had computed income taxes is as follows:

	Six Months Ended June 30, 2007		Year Ended December 31, 2006
Statutory rate	35.0	%	35.0	%
Statutory depletion	(5.2	)	2.5
State income tax, net of federal benefit	4.1		(3.0	)
Effective tax rate	33.9	%	34.5	%

The following table reconciles net income before taxes to pro forma federal taxable income for the periods indicated:

	Six Months Ended June 30, 2007		Year Ended December 31, 2006
	(unaudited)
	(in thousands)
Net income (loss) before taxes	$	8,794	$	(35,812	)
Depletion, depreciation and amortization for tax reporting purposes		709		53,943
Pro forma federal taxable income	$	9,503	$	18,131

The Partnership’s financial reporting bases of its net assets exceeded the tax bases of its net assets by $375.8 million and $374.1 million at December 31, 2006 and June 30, 2007, respectively.

The following table details pro forma net income reflecting a tax provision calculated on a separate return basis:

	Six Months Ended June 30, 2007			Year Ended December 31, 2006
	(in thousands)
Net income (loss) before taxes	$	8,794		$	(35,812	)
Tax (provision) benefit		(2,979	)		12,350
Pro forma net income (loss)	$	5,815		$	(23,462	)

F-8

PRO FORMA COMBINED SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)

Oil and Natural Gas Reserves

The following pro forma combined supplemental oil and gas information gives effect to the acquisition of the KCS Properties as though such acquisition had occurred on January 1, 2006.

Users of this information should be aware that the process of estimating quantities of proved and unproved 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 of HK Energy Partners LP Predecessor at June 30, 2007, December 31, 2006 and January 1, 2006, were prepared by Netherland, Sewell & Associates, Inc. (“Netherland, Sewell”), independent petroleum engineers. Their estimates of proved reserves have been made in accordance with SEC guidelines using constant oil and natural gas prices. All proved reserves are located in the United States of America.

The following table illustrates the Partnership’s pro forma 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 (MBbls)		Gas (MMcf)		Equivalent (MMcfe)
Proved reserves, January 1, 2006	9,450		125,413		182,113
Extensions and discoveries	—		181		181
Purchase of minerals in place	—		—		—
Production	(361	)	(7,951	)	(10,116	)
Sale of minerals in place	—		—		—
Revision of previous estimates(1)	(2,266	)	(9,942	)	(23,537	)
Proved reserves, December 31, 2006	6,823		107,701		148,641
Extensions and discoveries	22		406		537
Purchase of minerals in place	—		—		—
Production	(171	)	(3,746	)	(4,772	)
Sale of minerals in place	—		—		—
Revision of previous estimates	92		305		858
Proved reserves, June 30, 2007	6,766		104,666		145,264
Proved developed reserves, December 31, 2006	5,655		85,715		119,642
Proved developed reserves, June 30, 2007	5,519		82,320		115,432

(1) Negative revision was substantially the result of changes in commodity prices.

F-9

PRO FORMA COMBINED SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)

(CONTINUED)

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

The following information has been developed utilizing Statement of Financial Accounting Standards No. 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 Partnership’s engineering staff. It can be used for some comparisons, but should not be the only method used to evaluate the Partnership 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 Partnership.

The Partnership 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; and

• 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.

Under the Standardized Measure, future cash inflows were estimated by applying June 30, 2007 oil and natural gas prices to the estimated future production of year-end proved reserves. 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:

	Six Months Ended June 30, 2007			Year Ended Dec 31, 2006
	(in thousands)
Future cash inflows	$	1,200,560		$	994,480
Future production costs		(422,583	)		(368,372	)
Future development costs		(76,584	)		(74,489	)
Future net cash flows before income taxes		701,393			551,619
Future income tax expense		(1,830	)		(4,049	)
Future net cash flows before 10% discount		699,563			547,570
10% annual discount for estimated timing of cash flows		(382,477	)		(305,966	)
Standardized measure of discounted future net cash flows	$	317,086		$	241,604

F-10

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 Partnership’s pro forma proved oil and natural gas reserves during the year ended December 31, 2006 and the six months ended June 30, 2007.

	Six Months Ended June 30, 2007			Year Ended December 31, 2006
	(in thousands)
Beginning of year	$	241,604		$	404,492
Sale of oil and gas produced, net of production costs		(26,965	)		(58,069	)
Purchase of minerals in place		—			—
Sales of minerals in place		—			—
Extensions and discoveries		846			14
Changes in income taxes, net		2,219			(4,049	)
Changes in prices and production costs		71,573			(112,674	)
Changes in future development costs		(3,070	)		(16,199	)
Development costs incurred		6,103			32,117
Revisions of previous quantities		1,873			(38,421	)
Accretion of discount		12,283			40,449
Changes in production rates and other		10,620			(6,056	)
End of year	$	317,086		$	241,604

F-11

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Owners of

HK Energy Partners LP Predecessor:

Houston, Texas

We have audited the accompanying combined balance sheets of the HK Energy Partners LP Predecessor (“the Company”), as defined in Note 1 to the combined financial statements, as of December 31, 2006 and 2005 (successor), and the related combined statements of operations, changes in owner’s equity and cash flows for the year ended December 31, 2006 (successor), the period from July 28, 2005 to December 31, 2005 (successor), the period from January 1, 2005 to July 27, 2005 (predecessor) and the year ended December 31, 2004 (predecessor). These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements 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. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes 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, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such combined financial statements present fairly, in all material respects, the combined financial position of the Company as of December 31, 2006 and 2005 (successor), and the combined results of its operations and its cash flows for the year ended December 31, 2006 (successor), the period from July 28, 2005 to December 31, 2005 (successor), the period from January 1, 2005 to July 27, 2005 (predecessor) and the year ended December 31, 2004 (predecessor) in conformity with accounting principles generally accepted in the United States of America.

DELOITTE & TOUCHE LLP

Houston, Texas

October 29, 2007

F-12

HK ENERGY PARTNERS LP PREDECESSOR

(As Defined in Note 1)

Combined Balance Sheets

	December 31,
	2006			2005
	(in thousands)
ASSETS
Current assets:
Accounts receivable	$	6,703		$	4,179
Total current assets		6,703			4,179
Oil and gas properties(full cost method):
Evaluated		427,875			289,414
Unevaluated		112,575			10,674
Gross oil and gas properties		540,450			300,088
Less — accumulated depletion		(98,847	)		(21,917	)
Net oil and gas properties		441,603			278,171
Other noncurrent assets:
Goodwill		153,559			76,894
Debt issuance costs, net of amortization		2,489			1,233
Total assets	$	604,354		$	360,477
LIABILITIES AND OWNER’S EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	6,954		$	3,040
Total current liabilities		6,954			3,040
Long-term debt		269,337			198,737
Asset retirement obligations		6,394			2,275
Deferred income taxes		714			—
Commitments and contingencies (See Note 7)
Owner’s equity		320,955			156,425
Total liabilities and owner’s equity	$	604,354		$	360,477

See notes to the combined financial statements.

F-13

HK ENERGY PARTNERS LP PREDECESSOR

(As Defined in Note 1)

Combined Statements of Operations

	Successor						Predecessor
	Year Ended December 31, 2006			Period from July 28, 2005 to December 31, 2005(1)			Period from January 1, 2005 to July 27, 2005(1)			Year Ended December 31, 2004
	(in thousands)
Operating revenues:
Oil and gas	$	59,578		$	21,084		$	22,971		$	33,589
Operating expenses:
Production:
Lease operating		8,694			2,356			2,891			4,536
Workover and other		198			4			1			104
Taxes other than income		5,606			2,025			1,843			2,812
Gathering, transportation and other		878			176			110			188
Impairment expense		53,190			15,258			—			—
General and administrative		4,683			1,578			2,685			4,802
Depletion, depreciation and amortization		23,740			6,659			3,897			6,942
Total operating expenses		96,989			28,056			11,427			19,384
(Loss) income from operations		(37,411	)		(6,972	)		11,544			14,205
Interest expense and other		(18,953	)		(1,799	)		(6,205	)		(9,894	)
(Loss) income before income taxes	$	(56,364	)	$	(8,771	)	$	5,339		$	4,311
Income tax provision		(714	)		—			—			—
Net (loss) income	$	(57,078	)	$	(8,771	)	$	5,339		$	4,311

(1) Historical results of operations for the year ended December 31, 2005 have been divided into two periods. The first period from January 1, 2005 to July 27, 2005 represents the period of time prior to Petrohawk Energy Corporation’s ownership of HK Energy Partners LP Predecessor. The second period from July 28, 2005 to December 31, 2005 reflects the results of operations of HK Energy Partners LP Predecessor including the impact of Petrohawk’s purchase accounting adjustments as of July 28, 2005, the date of Petrohawk’s acquisition of Mission Resources Corporation.

See notes to the combined financial statements.

F-14

HK ENERGY PARTNERS LP PREDECESSOR

(As Defined in Note 1)

Combined Statement of Changes in Owner’s Equity

	Successor Equity			Predecessor Equity
	(in thousands)
Balance January 1, 2004	$	—		$	19,222
Net change in parent contributions					(3,764	)
Net Income		—			4,311
Balance December 31, 2004		—		$	19,769
Net change in parent contributions					(5,240	)
Net Income		—			5,339
Balance July 27, 2005		—		$	19,868
Net change in parent contributions		165,196			—
Net Loss		(8,771	)		—
Balance December 31, 2005	$	156,425			—
Net change in parent contributions		221,608			—
Net Loss		(57,078	)		—
Balance December 31, 2006	$	320,955		$	—

(1) Historical results of operations for the year ended December 31, 2005 have been divided into two periods. The first period from January 1, 2005 to July 27, 2005 represents the period of time prior to Petrohawk Energy Corporation’s ownership of HK Energy Partners LP Predecessor. The second period from July 28, 2005 to December 31, 2005 reflects the results of operations of HK Energy Partners LP Predecessor including the impact of Petrohawk’s purchase accounting adjustments as of July 28, 2005, the date of Petrohawk’s acquisition of Mission Resources Corporation.

See notes to the combined financial statements.

F-15

HK ENERGY PARTNERS LP PREDECESSOR

(As Defined in Note 1)

Combined Statement of Cash Flows

	Successor						Predecessor
	Year Ended December 31, 2006			Period From July 28, 2005 to December 31, 2005(1)			Period From January 1, 2005 to July 27, 2005(1)			Year Ended December 31, 2004
	(in thousands)
Cash flows from operating activities:
Net (loss) income	$	(57,078	)	$	(8,771	)	$	5,339		$	4,311
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion, depreciation and amortization		23,740			6,659			3,897			6,942
Income tax provision		714			—			—			—
Impairment expense		53,190			15,258			—			—
Other		(5,235	)		(300	)		14			14
Change in assets and liabilities, net of acquisitions:
Accounts receivable		(2,524	)		(4,179	)		(297	)		(1,485	)
Accounts payable and accrued liabilities		2,485			2,652			(1,853	)		614
Net cash provided by operating activities		15,292			11,319			7,100			10,396
Cash flows from investing activities:
Oil and gas capital expenditures		(238,436	)		(438	)		(9,731	)		(36,640	)
KCS capital expenditures		(497	)		—			—			—
Acquisition of oil and gas properties		(76,665	)		—			—			—
Other		3,915			(4	)		19			(559	)
Net cash used in investing activities		(311,683	)		(442	)		(9,712	)		(37,199	)
Cash flows from financing activities:
Equity contributions		140,339			—			—			—
Proceeds from borrowings		153,284			—			7,853			95,363
Repayment of borrowings		(76,871	)		—			—			(64,797	)
Debt issue costs		(1,630	)		—			—			—
Due from affiliates		10,877			(10,877	)		(5,241	)		(3,763	)
Due to affiliates		70,392			—			—			—
Net cash provided by financing activities		296,391			(10,877	)		2,612			26,803
Net increase (decrease) in cash		—			—			—			—
Cash at beginning of period		—			—			—			—
Cash at end of period	$	—		$	—		$	—		$	—
Certain cash and non-cash related items:
Cash paid for interest	$	18,943		$	6,540		$	6,205		$	9,894
Accrued capital expenditures	$	1,429		$	103		$	1,394		$	1,515

(1) Historical statement of cash flows for the year ended December 31, 2005 have been divided into two periods. The first period from January 1, 2005 to July 27, 2005 represents the period of time prior to Petrohawk Energy Corporation’s ownership of HK Energy Partners LP Predecessor. The second period from July 28, 2005 to December 31, 2005 reflects the results of operations of HK Energy Partners LP Predecessor including the impact of Petrohawk’s purchase accounting adjustments as of July 28, 2005, the date of Petrohawk’s acquisition of Mission Resources Corporation.

See notes to the combined financial statements.

F-16

HK ENERGY PARTNERS LP PREDECESSOR

NOTES TO THE COMBINED FINANCIAL STATEMENTS

1. Organization

General

HK Energy Partners LP (the “Partnership”) is a Delaware limited partnership formed in October 2007 by Petrohawk Energy Corporation (“Petrohawk”) to acquire, develop, exploit and produce oil and natural gas properties. The Partnership intends to consummate the initial public offering of its common units representing limited partnership interests. The Partnership has conducted no operations to date.

HK Energy Partners GP LP (“MLP GP, LP”) is a Delaware limited partnership formed in October 2007 as the general partner of the Partnership. MLP GP, LP is an indirect wholly-owned subsidiary of Petrohawk. MLP GP, LP owns a 2.0% general partner interest in the Partnership and all of the Partnership’s incentive distribution rights.

The Partnership will acquire all of the oil and natural gas properties (the “Partnership Properties”) comprising HK Energy Partners LP Predecessor (the “Predecessor” or the “Company”). As explained in Note 2 below, the Predecessor consists of a “carve-out” of the Partnership Properties from the consolidated financial statements of Mission Resources Corporation (“Mission”) for the period from January 1, 2004 through July 27, 2005, and from the consolidated financial statements of Petrohawk for the period from July 28, 2005 through December 31, 2006. The Company is not now, and has not been, a separately identifiable legal entity from Mission or Petrohawk, nor has it operated independently from Mission or Petrohawk.

Petrohawk acquired Mission by merger on July 28, 2005, and acquired proved reserves along the Texas and Louisiana Gulf Coast and in the Permian Basin in West Texas and southeastern New Mexico. Mission ceased operations as a separately identifiable legal entity upon its merger with Petrohawk. The Company includes proved reserves located in the Permian Basin in West Texas and southeastern New Mexico that were acquired from Mission by Petrohawk in the merger (the “Mission Properties”) as of December 31, 2006.

Petrohawk acquired KCS Energy, Inc. (“KCS”), by merger on July 12, 2006, and acquired proved reserves along the Mid-Continent (Anadarko and Arkoma basins) and onshore Gulf Coast regions of the United States. KCS ceased operations as a separately identifiable legal entity upon its merger with Petrohawk. The Company includes proved reserves located in the Permian Basin in West Texas that were acquired from KCS by Petrohawk in the merger (the “KCS Properties”) as of December 31, 2006.

2. Summary of Significant Accounting Policies

Basis of Presentation

The Mission Properties were determined to be the predecessor of the Company in accordance with the Rules and Regulations of the U.S. Securities and Exchange Commission (“SEC”). As common control exists over the Partnership Properties, the Company’s financial statements reflect the following financial statements on a combined basis for the periods noted: (1) carved-out combined financial statements of the Mission Properties for the year ended December 31, 2004 and the period from January 1, 2005 through July 27, 2005 and (2) carved-out combined financial statements of the Mission Properties and the KCS Properties (from the time acquired by Petrohawk in July 2006) for the period from July 28, 2005 to December 31, 2005 and the year ended December 31, 2006. Financial data for the period prior to Petrohawk’s acquisition of Mission has been separated by a bold black line.

The Company’s financial position, results of operations and cash flows as of and for the periods presented reflect allocations based upon the historical accounts of Mission and in relation to Petrohawk’s acquisitions of

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Mission and of KCS that are based on the percentage of the Mission and KCS estimated proved reserves included in the Partnership Properties (See Notes 3, Acquisitions, and 4, Oil and Natural Gas Properties, for additional information). These allocations are not necessarily indicative of the costs and expenses that would have resulted had the Company been operated as a stand-alone entity.

Throughout the periods covered by the combined financial statements, Petrohawk managed cash through a centralized treasury system including all of the Company’s settlements of revenue and expense transactions and payments made or received on behalf of the Company with third parties. These transactions are reflected as a component of owner’s equity on the combined balance sheets and a component of cash from financing activities in the combined statements of cash flows. Subsequent to completion of the offering, Petrohawk will continue to provide cash management services; however, revenues settled and expenses and costs paid on behalf of the Company will be cash settled on a monthly basis using HK Energy Partners LP bank accounts.

The employees supporting the Company’s operations are employees of Petrohawk. The Company’s combined financial statements include costs allocated by Petrohawk for centralized general and administrative services performed by Petrohawk. Costs allocated to the Company were based on identification of Petrohawk’s resources which directly benefit the Company. All of the allocations are based on assumptions that management believes are reasonable; however, these allocations are not necessarily indicative of the costs and expenses that would have resulted if the Company had been operated as a stand-alone entity. These allocations were historically not settled in cash and resulted in adjustments to owner’s equity.

Use of Estimates

The preparation of the Company’s combined financial statements in conformity with GAAP requires 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 combined 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 and the calculation of the Company’s full cost ceiling test. 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 combined 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, 2006 and 2005.

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 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 percent.

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Costs associated with unevaluated properties are excluded from the full cost pool until we have 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.

Income Taxes

No provision for federal or state income taxes is made in our combined financial statements except for the Texas margin tax which is an income tax assessed at the Company level because the taxable income or loss will be included in the income tax returns of the individual partners of the Partnership with the exception of Texas franchise taxes.

A reconciliation between the statutory federal income tax rate and the effective income tax rate as income taxes were included in the financial statements as follows:

	Successor				Predecessor
	Year Ended December 31, 2006		Period from July 28, 2005 to December 31, 2005		Period from January 1, 2005 to July 27, 2005		Year Ended December 31, 2004
Statutory rate	35.0	%	35.0	%	35.0	%	35.0	%
Statutory depletion	—		0.3		(0.6	)	(0.1	)
State income tax, net of federal benefit	(0.9	)	(4.5	)	0.3		3.0
Effective tax rate	34.1	%	30.8	%	34.7	%	37.9	%

The following table reconciles net income before income taxes to pro forma federal taxable income for the periods indicated (in thousands, unaudited):

	Successor						Predecessor
	Year Ended December 31, 2006			Period from July 28, 2005 to December 31, 2005			Period from January 1, 2005 to July 27, 2005			Year Ended December 31, 2004
Net (loss) income before taxes	$	(56,364	)	$	(8,771	)	$	5,339		$	4,311
Depreciation, depletion and amortization for tax reporting purposes		51,307			19,576			(6,199	)		(1,009	)
Pro forma federal taxable (loss) income	$	(5,057	)	$	10,805		$	(860	)	$	3,302

The Company’s financial reporting bases of its net assets exceeded the tax bases of its net assets by $375.8 million, $250.5 million, $97.6 million and $94.0 million for the tax year ending December 31, 2006 (successor), period from July 28, 2005 to December 31, 2005 (successor), period from January 1, 2005 to July 27, 2005 (predecessor) and year ending December 31, 2004 (predecessor), respectively.

The following table details pro forma net income reflecting a tax provision calculated on a separate return basis (in thousands):

	Successor						Predecessor
	Year Ended December 31, 2006			Period from July 28, 2005 to December 31, 2005			Period from January 1, 2005 to July 27, 2005			Year Ended December 31, 2004
Net income (loss) before taxes	$	(56,364	)	$	(8,771	)	$	5,339		$	4,311
Tax provision		19,213			2,709			(1,853	)		(1,635	)
Pro forma net (loss) income	$	(37,151	)	$	(6,062	)	$	3,486		$	2,676

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Revenue Recognition

The Company recognizes oil and natural gas sales upon delivery to the purchaser. Under the sales method, the Company and other joint owners may sell more or less than their entitled share of the natural gas volume produced. Should the Company’s excess sales of natural gas exceed its share of estimated remaining recoverable reserves, a liability is recorded by the Company and revenue is deferred.

Asset Retirement Obligation

Statement of Financial Accounting Standards No. 143,Accounting for Asset Retirement Obligations (“FAS 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. The Company has 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. 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 these indicators suggest a material change in the estimated obligations on an interim basis, 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. Statement of Financial Accounting Standards No. 142,Goodwill and Other Intangible Assets (“FAS 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 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 write down is charged against earnings.

Petrohawk’s acquisitions of Mission and KCS generated approximately $130.0 million (of which $76.9 million has been allocated to the Company) and $768.2 million (of which $76.7 million has been allocated to the Company) of goodwill, respectively. The Company’s combined financial statements include an allocation of such goodwill based upon the total goodwill recognized for each individual transaction by Petrohawk at the date of acquisition times the ratio of the estimated proved reserves (volumes) acquired by the Company over the total estimated proved reserves acquired by Petrohawk in such transaction.

The Company completed its annual impairment review during the third quarter of 2006. No impairment was deemed necessary. Downward revisions of estimated proved 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 Financial Accounting Standards Board (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, accounts receivable and accounts payable approximates their carrying value due to their short-term nature.

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As explained in Note 5, “Long-Term Debt”, a portion of Petrohawk’s long-term debt under its senior revolving credit facility, 9 ¹/8% senior notes and 7 ¹/8% senior notes that was incurred in connection with Petrohawk’s acquisitions of Mission and of KCS has been allocated to the Company. The estimated fair value of the Company’s allocated debt under the senior revolving credit facility approximates carrying value because the facility carries an interest rate that approximates current market rates. The following table presents the estimated fair values of the Company’s allocated debt as of December 31, 2006 excluding discounts and premiums:

	December 31, 2006
Debt(In thousands)	Carrying Amount		Estimated Fair Value
Senior revolving credit facility	$	115,790	$	115,790
9 1/8% $650 mm senior notes		128,807		134,282
7 1/8% $275 mm senior notes		27,445		26,621
	$	272,042	$	276,693

Recently Issued Accounting Pronouncements

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 and 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 and cash flows.

3. Acquisitions

Mission Resources Corporation

On July 28, 2005, Mission merged with, and into, Petrohawk. The merger was accounted for using the purchase method of accounting under the accounting standards established in SFAS No. 141,Business Combinations (“FAS 141”) and FAS 142 “Goodwill and Other Intangible Assets.” Petrohawk reflected the results of operations of Mission beginning July 28, 2005. Petrohawk recorded the estimated fair values of the assets acquired and liabilities assumed at July 28, 2005.

In the combined financial statements, the beginning evaluated property balance at January 1, 2004 was calculated based upon Mission’s historical oil and gas property balance times the ratio of estimated proved reserves (volumes) of the properties included in the combined financial statements to Mission’s total estimated proved reserves. At the time of the Mission acquisition by Petrohawk, the property balance was revalued to fair value based upon the total acquisition cost of Mission times the ratio of estimated proved reserves (volumes) of

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the properties included in the combined financial statements to Mission’s total estimated proved reserves. Specific identification was used to allocate unevaluated property balances. Asset retirement obligations resulting from the Mission acquisition were allocated to the Company as of July 28, 2005, based on the specific properties included in the combined financial statements. Petrohawk’s acquisition of Mission generated approximately $130.0 million of goodwill. The Company’s combined financial statements include an allocation of such goodwill based upon the goodwill recognized for each individual transaction by Petrohawk at the date of acquisition times the ratio of the estimated proved reserves (volumes) acquired by the Company over the total estimated proved reserves acquired by Petrohawk in such transaction.

KCS Energy, Inc.

On July 12, 2006, KCS merged with and into Petrohawk. The merger with KCS was accounted for using the purchase method of accounting under the accounting standards established in FAS 141 and FAS 142. Petrohawk reflected the results of operations of KCS beginning July 12, 2006. Petrohawk recorded the estimated fair values of the assets acquired and liabilities assumed at July 12, 2006.

In the combined financial statements, the Company’s basis in the KCS Properties was calculated as Petrohawk’s total acquisition cost of KCS times the ratio of estimated proved reserves (volumes) of the properties included in the combined financial statements to KCS’ total estimated proved reserves. Specific identification was used to allocate unevaluated property balances. Asset retirement obligations resulting from the KCS acquisition were allocated to the Company as of July 12, 2006, based on the specific properties included in the combined financial statements. Petrohawk’s acquisition of KCS generated approximately $768.2 million of goodwill. The Company’s combined financial statements include an allocation of such goodwill based upon the total goodwill recognized for each individual transaction by Petrohawk at the date of acquisition times the ratio of the estimated proved reserves (volumes) acquired by the Company over the total estimated proved reserves acquired by Petrohawk in such transaction.

Pro Forma Results of Operations for the Company’s Acquisition of the KCS Properties

The Company’s unaudited pro forma results of operations for the years ended December 31, 2006 and 2005 are 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 acquisition of the KCS Properties had been completed on January 1, 2006 and 2005. The unaudited pro forma results of operations do not purport to represent the actual results of operations had the acquisition in fact occurred on such date or to project the Company’s results of operations for any future date or period.

	For the Years Ended December 31,
	2006			2005
	(Unaudited)
	(In thousands, except per share data)
Pro forma:
Oil and gas revenues	$	78,285		$	80,162
Net loss	$	(55,392	)	$	(7,087	)

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4. Oil and Natural Gas Properties

Oil and natural gas properties as of December 31, 2006 and 2005 consisted of the following:

	December 31,
	2006			2005
	(In thousands)
Subject to depletion	$	427,875		$	289,414
Not subject to depletion:
Incurred in 2006		101,919			—
Incurred in 2005 and prior		10,656			10,674
Total not subject to depletion		112,575			10,674
Gross oil and gas properties		540,450			300,088
Less accumulated depletion		(98,847	)		(21,917	)
Net oil and gas properties	$	441,603		$	278,171

The Company uses the full cost method of accounting for its investment in oil and natural gas properties. Under this method of accounting, all costs of acquisition, exploration and development of oil and natural gas reserves (including such costs as leasehold acquisition costs, geological expenditures, dry hole costs, tangible and intangible development costs and direct internal costs) are capitalized as the cost of oil and natural gas properties when incurred. To the extent that capitalized costs of oil and natural gas properties, net of accumulated depletion exceed the discounted future net revenues of proved oil and natural gas reserves net of deferred taxes, such excess capitalized costs 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.

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 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 $135.3 million 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 resulted in an impairment of $53.2 million before taxes. 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.

At December 31, 2005, the ceiling test value of the Company’s reserves was calculated based on the December 31, 2005 West Texas Intermediate price of $61.04 per barrel and the Henry Hub spot market price of $11.22 per MMBtu. The Company had not previously elected to use subsequent pricing. As a result, the Company recorded an impairment of $15.3 million.

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;

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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.

5. Long-Term Debt

Petrohawk assumed and incurred debt of $199.0 million and $70.0 million in connection with its acquisitions of Mission and KCS. The combined financial statements reflect an allocation of a portion of the debt assumed and incurred by Petrohawk to the Company based upon the ratio of the estimated proved reserves (volumes) of the properties acquired in such acquisition that are included in the combined financial statements to Mission’s total estimated proved reserves, in the case of the Mission acquisition, and to KCS’s total estimated proved reserves, in the case of the KCS acquisition.

The following table presents the components of Petrohawk’s acquisition-related debt that has been allocated to the Company as of December 31, 2006 and 2005:

	December 31,
	2006		2005
	(In thousands)
Senior revolving credit facility	$	115,790	$	115,790
9 1/8% $650 million senior notes(1)		127,310		—
7 1/8% $275 million senior notes(2)		26,237		—
9 7/8% senior notes(3)		—		82,947
	$	269,337	$	198,737

(1) Amount includes a $1.5 million discount recorded by the Company in conjunction with Petrohawk’s issuance of the 9 ¹/8% Senior Notes as of December 31, 2006. See “9 ¹/8% Senior Notes” below for additional detail.

(2) Amount includes a $1.2 million discount recorded by the Company in conjunction with Petrohawk’s assumption of 7 ¹/8% Senior Notes as of December 31, 2006. See “7 ¹/8% Senior Notes” below for additional detail.

(3) Amount includes a $6.1 million premium recorded by the Company in conjunction with Petrohawk’s assumption of the 9 ⁷/8% Senior Notes as of December 31, 2005. These notes were repaid by Petrohawk in conjunction with its issuance of the 9 ¹/8% Senior Notes in July 2006. See “9 ⁷/8% Senior Notes” below for additional detail.

Debt Maturity Table

The following table presents the scheduled maturities of the allocated principal amounts of Petrohawk’s long-term debt allocated to the Company (in thousands).

2007	$	—
2008		—
2009		—
2010		115,790
2011		—
Thereafter		156,252
	$	272,042

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Senior Revolving Credit Facility

The Company’s combined financial statements include a carve-out allocation of $115.8 million of debt outstanding on Petrohawk’s senior revolving credit facility. This allocation was based upon the cash requirements of Petrohawk’s merger with Mission and the ratio of estimated proved reserves acquired from Mission that are included in the combined financial statements to the total estimated proved reserves acquired by Petrohawk in its acquisition of Mission. No borrowings under the senior revolving credit facility were required for the KCS Properties acquisition.

Petrohawk’s amended and restated senior revolving credit facility provides for a $1 billion commitment with a borrowing base that is 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, which is determined based on Petrohawk’s oil and natural gas properties, reserves, other indebtedness and other relevant factors. At December 31, 2006, the borrowing base was $710 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. Borrowings are secured by first priority liens on substantially all of Petrohawk’s assets and all of the assets of, and equity interest in, Petrohawk’s subsidiaries. Amounts drawn on the facility mature on July 12, 2010.

The revolving credit facility contains customary financial and other covenants, including minimum working capital levels, minimum coverage of interest expense, and a maximum leverage ratio. In addition, Petrohawk is subject to covenants limiting dividends and other restricted payments, transactions with affiliates, incurrence of debt, changes of control, asset sales, and liens on properties. At December 31, 2006, Petrohawk was in compliance with all of its debt covenants under the revolving credit facility.

7 ¹/8% Senior Notes

The Company’s combined financial statements include a carve-out allocation of $27.4 million of Petrohawk’s $275 million of 7 ¹/8% Senior Notes due 2012 (the “2012 Notes”). This allocation was based upon the ratio that the estimated proved reserves included in the combined financial statements bear to the total estimated proved reserves acquired by Petrohawk in its merger with KCS. The Company’s combined financial statements also include the carve-out of $1.2 million of the overall $13.6 million discount originally recognized in conjunction with the assumption of these notes by Petrohawk at December 31, 2006, based upon the same allocation methodology.

As part of its merger with KCS, Petrohawk assumed (pursuant to the Second Supplemental Indenture relating to the 2012 Notes, and subsidiaries of Petrohawk guaranteed (pursuant to the Third Supplemental Indenture relating to such notes), all the obligations (approximately $275 million) of KCS under the 2012 Notes and the Indenture dated April 1, 2004 (the 2012 Indenture) among KCS, U.S. Bank National Association, as trustee, and the subsidiary guarantors named therein, which governs the terms of the 2012 Notes. Interest on the 2012 Notes is payable semi-annually, on each April 1 and October 1. On or after April 1, 2008, Petrohawk 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, Petrohawk 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

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The 2012 Indenture contains a provision requiring Petrohawk to offer to purchase the 2012 Notes at 101% of face value in the event of a change of control (as defined in the 2012 Indenture). At December 31, 2006, Petrohawk was in compliance with all of its debt covenants under the 2012 Notes.

In conjunction with the assumption of the 2012 Notes, Petrohawk 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 $12.5 million at December 31, 2006.

The 2012 Notes are jointly and severally and fully and unconditionally guaranteed on a senior unsecured basis by all of Petrohawk’s subsidiaries. Petrohawk Energy Corporation, the issuer of the 2012 Notes, has no material independent assets or operations apart from the assets and operations of its subsidiaries.

9 ¹/8% Senior Notes

The Company’s combined financial statements include a carve-out allocation of $128.8 million of Petrohawk’s $650 million of 9 ¹/8% Senior Notes due 2013 (the “2013 Notes”) issued on July 12, 2006 in conjunction with Petrohawk’s merger with KCS and its repayment of the 9 ⁷/8% Senior Notes discussed below ($76 million of which has been allocated to the Company). This allocation is based upon the ratio of estimated proved reserves included in the combined financial statements to the total estimated proved reserves acquired by Petrohawk in its merger with KCS. In addition, the Company’s combined financial statements also include the carve-out of $1.5 million of the overall $8.2 million discount originally recognized in conjunction with the issuance of the $650 million of 9 ¹/8% Senior Notes.

On July 12, 2006 and July 27, 2006, Petrohawk consummated private placements of $650 million and $125 million, respectively, of the 2013 Notes, pursuant to an Indenture dated as of July 12, 2006 (2013 Indenture) and First Supplemental Indenture to the 2013 Notes (the 2013 First Supplemental Indenture), among Petrohawk, Petrohawk’s subsidiaries named therein as guarantors, and U.S. Bank National Association, as trustee. The first tranche of $650 million in 2013 Notes was 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. Petrohawk applied a portion of the net proceeds from the initial sale to fund the cash consideration paid by Petrohawk to the KCS stockholders in connection with Petrohawk’s merger with KCS and Petrohawk’s repurchase of the 9 ⁷/8% Senior Notes due 2011 pursuant to a tender offer Petrohawk concluded in July 2006. The additional $125 million in 2013 Notes were issued pursuant to the same Indenture at 101.125% of the face amount. Petrohawk applied the net proceeds from the sale of the additional 2013 Notes to repay indebtedness outstanding under its senior revolving credit facility. The Company’s combined financial statements do not include a carve-out allocation of this tranche of 2013 Notes as these notes were not issued in conjunction with the acquisition of KCS.

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 Petrohawk and rank equally with all of its current and future senior indebtedness, including the 2012 Notes. The 2013 Notes rank effectively subordinate to Petrohawk’s secured debt to the extent of the collateral, including secured debt under the revolving credit facility, and senior to any future subordinated indebtedness. The 2013 Notes are jointly and severally and fully and unconditionally guaranteed on a senior unsecured basis by all of Petrohawk’s subsidiaries. Petrohawk, the issuer of the 2013 Notes, has no material independent assets or operations apart from the assets and operations of its subsidiaries.

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

F-26

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

On or after July 15, 2010, Petrohawk 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, Petrohawk 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

Petrohawk 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, Petrohawk 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 Petrohawk 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 Petrohawk’s assets. Additionally, the 2013 Indenture covering the 2013 Notes contains a provision which provides for a rate increase of 1/8 of one percent if Petrohawk refinances any part of its 2012 Notes on or before July 11, 2007.

At December 31, 2006, Petrohawk was in compliance with all of its debt covenants relating to the 2013 Notes.

9 ⁷/8% Senior Notes

The Company’s combined financial statements include a carve-out allocation of $76.9 million of Petrohawk’s $130 million 9 ⁷/8% Senior Notes due 2011 (the “2011 Notes”), which Petrohawk assumed in conjunction with its merger with Mission. This allocation was based upon the ratio that the estimated proved reserves included in the combined financial statements bears to the total estimated proved reserves acquired by Petrohawk in its merger with Mission. In addition, the Company’s combined financial statements also include the carve-out of $6.6 million of the overall $11.1 million premium originally recognized in conjunction with the assumption of the 2011 Notes. The 2011 Notes were substantially extinguished in conjunction with the Company’s merger with KCS.

On April 8, 2004, Mission Resources Corporation issued $130.0 million of its 2011 Notes. Petrohawk assumed these notes upon the closing of its merger with Mission. In conjunction with Petrohawk’s merger with KCS, Petrohawk extinguished substantially all of its 2011 Notes for a premium of $14.9 million plus accrued interest of $3.5 million. There were approximately $0.3 million of the notes which were not redeemed and were still outstanding as of December 31, 2006. In connection with the extinguishment of substantially all of the 2011 Notes, Petrohawk requested and received from the noteholders consent to eliminate most significant debt covenants associated with the 2011 Notes.

F-27

Debt Issuance Costs

The Company capitalizes certain direct costs associated with the issuance of long-term debt. The combined financial statements reflect an allocation of a portion of debt issuance costs based upon the ratio of the estimated proved reserves (volumes) of the properties acquired in such acquisition that are included in the combined financial statements to Mission’s and KCS’ respective total estimated proved reserves for each acquisition. At December 31, 2006 and 2005, the Company had approximately $2.5 million and $1.2 million of net debt issuance costs being amortized over the lives of the respective debt on a straight line basis.

6. 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 an asset retirement obligation (“ARO”) liability on the 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 as part of the full cost pool.

The Company recorded the following activity related to the ARO liability for the year ended December 31, 2006 (successor), the period from January 1, 2005 to July 27, 2005 (predecessor) and the period from July 28, 2005 to December 31, 2005 (successor) (in thousands):

Liability for asset retirement obligation as of January 1, 2005 (predecessor)	$	438
Liabilities settled and divested		(15	)
Additions		34
Accretion expense		14
Liability for asset retirement obligation as of July 27, 2005 (predecessor)		471
Liabilities settled and divested		(11	)
Additions		6
Acquisitions(1)		1,771
Accretion expense		38
Liability for asset retirement obligation as of December 31, 2005 (successor)		2,275
Liabilities settled and divested		(169	)
Additions		79
Acquisitions(1)		4,005
Accretion expense		204
Liability for asset retirement obligation as of December 31, 2006 (successor)	$	6,394

(1) Refer to Note 3 “Acquisitions” for more details on these acquisitions.

7. 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 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 financial position, results of operations or cash flow.

F-28

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, 2006 (successor), 2005 (successor) and 2004 (predecessor) and January 1, 2004 (predecessor) were prepared by Netherland, Sewell & Associates, Inc., the Company’s independent consulting petroleum engineers. Their estimates of proved reserves have been made in accordance with SEC guidelines using constant oil and natural gas prices as of December 31, 2006. All proved reserves are located in the United States of America.

F-29

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, and Associates.

	Proved Reserves
	Successor Company						Predecessor Company						Total
	Oil (MBbls)		Gas (MMcf)		Equivalent (MMcfe)		Oil (MBbls)		Gas (MMcf)		Equivalent (MMcfe)		Oil (MBbls)		Gas (MMcf)		Equivalent(1) (MMcfe)
Proved reserves, January 1, 2004	—		—		—		5,563		24,911		58,287		5,563		24,911		58,287
Extensions and discoveries	—		—		—		521		28,848		31,974		521		28,848		31,974
Purchase of minerals in place	—		—		—		2,511		11,030		26,095		2,511		11,030		26,095
Production	—		—		—		(402	)	(3,518	)	(5,929	)	(402	)	(3,518	)	(5,929	)
Revision of previous estimates	—		—		—		358		14,562		16,715		358		14,562		16,715
Proved reserves, December 31, 2004	—		—		—		8,551		75,833		127,142		8,551		75,833		127,142
Extensions and discoveries	—		—		—		—		—		—		—		—		—
Purchase of minerals in place	—		—		—		—		—		—		—		—		—
Production	—		—		—		(226	)	(1,957	)	(3,315	)	(226	)	(1,957	)	(3,315	)
Sale of minerals in place	—		—		—		—		—		—		—		—		—
Revision of previous estimates	—		—		—		(1,358	)	7,926		(223	)	(1,358	)	7,926		(223	)
Proved reserves, July 27, 2005	—		—		—		6,967		81,802		123,604		6,967		81,802		123,604
Extensions and discoveries	36		108		324		—		—		—		36		108		324
Purchase of minerals in place	6,967		81,802		123,604		—		—		—		6,967		81,802		123,604
Production	(160	)	(1,662	)	(2,621	)	—		—		—		(160	)	(1,662	)	(2,621	)
Sale of minerals in place	—		—		—		(6,967	)	(81,802	)	(123,604	)	(6,967	)	(81,802	)	(123,604	)
Revision of previous estimates	2,528		(7,015	)	8,152		—		—		—		2,528		(7,015	)	8,152
Proved reserves, December 31, 2005	9,371		73,233		129,459		—		—		—		9,371		73,233		129,459
Extensions and discoveries	—		181		181		—		—		—		—		181		181
Purchase of minerals in place	77		42,278		42,738		—		—		—		77		42,278		42,738
Production	(356	)	(5,646	)	(7,780	)	—		—		—		(356	)	(5,646	)	(7,780	)
Sale of minerals in place	—		—		—		—		—		—		—		—		—
Revision of previous estimates	(2,269	)	(2,345	)	(15,957	)	—		—		—		(2,269	)	(2,345	)	(15,957	)
Proved reserves, December 31, 2006	6,823		107,701		148,641		—		—		—		6,823		107,701		148,641
	Proved Developed Reserves
December 31, 2004							11,474		31,609		100,451		11,474		31,609		100,451
December 31, 2005	10,251		28,242		89,748								10,251		28,242		89,748
December 31, 2006	9,946		59,968		119,642								9,946		59,968		119,642

(1) Calculated using natural gas equivalents of six Mcf of natural gas per Bbl of oil or NGL. NGLs are included in natural gas.

F-30

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 depletion, depreciation and amortization.

	December 31,
	2006			2005
	(in thousands)
Evaluated properties	$	427,875		$	289,414
Unevaluated properties		112,575			10,674
		540,450			300,088
Accumulated depletion, depreciation and amortization		(98,847	)		(21,917	)
	$	441,603		$	278,171

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):

	Successor Company				Predecessor Company
	Year Ended December 31, 2006		Period from July 28, 2005 to December 31, 2005		Period from January 1, 2005 to July 27, 2005		Year Ended December 31, 2004
Property acquisition costs, proved	$	117,728	$	285,531	$	—	$	23,946
Property acquisition costs, unproved		101,918		13,753		—		—
Exploration and extension well costs		1,203		—		—		—
Development costs		19,513		804		8,338		7,852
Total costs	$	240,362	$	300,088	$	8,338	$	31,798

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 (“FAS 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 Flows 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; and

• 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.

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. The resulting net cash flows are

F-31

reduced to present value amounts by applying a 10% discount factor. Use of a 10% discount rate and year-end prices is required by FAS 69.

The Standardized Measure is as follows (in thousands):

	Successor Company						Predecessor Company
	December 31,						July 27, 2005			December 31, 2004
	2006			2005
Future cash inflows	$	994,480		$	982,402		$	984,292		$	750,146
Future production costs		(368,372	)		(310,039	)		(198,906	)		(248,441	)
Future development costs		(74,489	)		(47,284	)		(33,397	)		(41,162	)
Future net cash flows before income taxes		551,619			625,079			751,989			460,543
Future income tax expense		(4,049	)		—			—			—
Future net cash flows before 10% discount		547,570			625,079			751,989			460,543
10% annual discount for estimated timing of cash flows		(305,966	)		(357,582	)		(469,701	)		(265,302	)
Standardized measure of discounted future net cash flows	$	241,604		$	267,497		$	282,288		$	195,241

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, 2006 (in thousands).

	Successor Company						Predecessor Company
	Year Ended December 31, 2006			Period From July 28, 2005 to December 31, 2005			Period from January 1, 2005 to July 27, 2005			Year Ended December 31, 2004
Beginning of period	$	267,497		$	282,288		$	195,241		$	83,971
Sale of oil and gas produced, net of production costs		(43,576	)		(16,385	)		(17,855	)		(25,555	)
Purchase of minerals in place		94,749			—			—			—
Extensions and discoveries		14			1,147			—			39,577
Changes in income taxes, net		(4,049	)		—			—			—
Changes in prices and production costs		(70,224	)		(59,798	)		105,390			53,394
Changes in future development costs		(14,380	)		(6,270	)		(202	)		(7,865	)
Development costs incurred		19,434			804			8,304			7,839
Revisions of previous quantities		(26,496	)		16,918			(501	)		36,208
Accretion of discount		26,750			12,142			11,126			8,397
Changes in production rates and other		(8,115	)		36,651			(19,215	)		(725	)
End of period	$	241,604		$	267,497		$	282,288		$	195,241

F-32

HK ENERGY PARTNERS LP PREDECESSOR

(As Defined in Note 1)

Condensed Combined Balance Sheets

Unaudited

	June 30, 2007			December 31, 2006
	(in thousands)
ASSETS
Current assets:
Accounts receivable	$	6,711		$	6,703
Total current assets		6,711			6,703
Oil and gas properties(full cost method):
Evaluated		435,226			427,875
Unevaluated		112,575			112,575
Gross oil and gas properties		547,801			540,450
Less — accumulated depletion		(111,881	)		(98,847	)
Net oil and gas properties		435,920			441,603
Other noncurrent assets:
Goodwill		153,559			153,559
Debt issuance costs, net of amortization		2,285			2,489
Total assets	$	598,475		$	604,354
LIABILITIES AND OWNER’S EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	3,955		$	6,954
Total current liabilities		3,955			6,954
Long-term debt		269,625			269,337
Asset retirement obligations		6,579			6,394
Deferred income taxes		764			714
Commitments and contingencies (See Note 7)
Owner’s equity		317,552			320,955
Total liabilities and owner’s equity	$	598,475		$	604,354

See notes to the combined financial statements.

F-33

HK ENERGY PARTNERS LP PREDECESSOR

(As Defined in Note 1 )

Condensed Combined Statements of Operations

Unaudited

	For the Six Months Ended June 30,
	2007			2006
	(in thousands)
Operating revenues:
Oil and gas	$	37,272		$	22,225
Operating expenses:
Production:
Lease operating		5,536			3,550
Workover and other		38			9
Taxes other than income		3,664			1,727
Gathering, transportation and other		824			158
General and administrative		2,873			1,711
Depletion, depreciation and amortization		13,034			7,052
Total operating expenses		25,969			14,207
Income from operations		11,303			8,018
Interest expense and other		(11,882	)		(7,442	)
(Loss) income before income taxes		(579	)		576
Income tax provision		(50	)		(576	)
Net loss	$	(629	)	$	—

See notes to the combined financial statements.

F-34

HK ENERGY PARTNERS LP PREDECESSOR

(As Defined in Note 1)

Condensed Combined Statements of Cash Flows

Unaudited

	Six Months Ended June 30, 2007			Six Months Ended June 30, 2006
	(in thousands)
Cash flows from operating activities:
Net (loss) income	$	(629	)	$	—
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion, depreciation and amortization		13,034			7,052
Income tax expense		50			576
Other		664			(359	)
Change in assets and liabilities, net of acquisitions:
Accounts receivable		(8	)		460
Accounts payable and accrued liabilities		(1,805	)		(506	)
Net cash provided by operating activities		11,306			7,223
Cash flows from investing activities:
Oil and gas capital expenditures		(8,545	)		(6,282	)
Other		13			(29	)
Net cash used in investing activities		(8,532	)		(6,311	)
Cash flows from financing activities:
Due from affiliates		—			(912	)
Due to affiliates		(2,774	)		—
Net cash used in financing activities		(2,774	)		(912	)
Net increase (decrease) in cash		—			—
Cash at beginning of period		—			—
Cash at end of period	$	—		$	—

See notes to the combined financial statements.

F-35

HK ENERGY PARTNERS LP PREDECESSOR

NOTES TO THE CONDENSED COMBINED FINANCIAL STATEMENTS

(UNAUDITED)

1. Organization

General

HK Energy Partners LP (the “Partnership”) is a Delaware limited partnership formed in October 2007 by Petrohawk Energy Corporation (“Petrohawk”) to acquire, develop, exploit and produce oil and natural gas properties. The Partnership intends to consummate the initial public offering of its common units representing limited partnership interests. The Partnership has conducted no operations to date.

HK Energy Partners GP LP (“MLP GP, LP”) is a Delaware limited partnership formed in October 2007 as the general partner of the Partnership. MLP GP, LP is an indirect wholly-owned subsidiary of Petrohawk. MLP GP, LP owns a 2.0% general partner interest in the Partnership and all of the Partnership’s incentive distribution rights.

As part of the Formation Transactions, the Partnership will acquire all of the oil and natural gas properties (the “Partnership Properties”) comprising HK Energy Partners LP Predecessor (the “Predecessor” or the “Company”). As explained in Note 2 below, the Predecessor consists of a “carve-out” of the Partnership Properties from the consolidated financial statements of Mission Resources Corporation (“Mission”) for the period from January 1, 2004 through July 27, 2005, and from the consolidated financial statements of Petrohawk for the period from July 28, 2005 through June 30, 2007. The Company is not now, and has not been, a separately identifiable legal entity from Mission or Petrohawk, nor has it operated independently from Mission or Petrohawk.

Petrohawk acquired Mission by merger on July 28, 2005, and acquired proved reserves along the Texas and Louisiana Gulf Coast and in the Permian Basin in West Texas and southeastern New Mexico. Mission ceased operations as a separately identifiable legal entity upon its merger with Petrohawk. The Company includes proved reserves located in the Permian Basin in West Texas and southeastern New Mexico that were acquired from Mission by Petrohawk in the merger (the “Mission Properties”) as of December 31, 2006.

Petrohawk acquired KCS Energy, Inc. (“KCS”), by merger on July 12, 2006, and acquired proved reserves along the Mid-Continent (Anadarko and Arkoma basins) and onshore Gulf Coast regions of the United States. KCS ceased operations as a separately identifiable legal entity upon its merger with Petrohawk. The Company includes proved reserves located in the Permian Basin in West Texas that were acquired from KCS by Petrohawk in the merger (the “KCS Properties”) as of December 31, 2006.

2. Summary of Significant Accounting Policies

Basis of Presentation

The Mission Properties were determined to be the predecessor of the Company in accordance with the Rules and Regulations of the U.S. Securities and Exchange Commission (“SEC”). As common control exists over the Partnership Properties, the Company’s financial statements reflect the following financial statements on a combined basis for the periods noted: (1) carved-out combined financial statements of the Mission Properties for the year ended December 31, 2004 and the period from January 1, 2005 through July 27, 2005 and (2) carved-out combined financial statements of the Mission Properties and the KCS Properties (from the time acquired by Petrohawk in July 2006) for the period from July 28, 2005 to December 31, 2005 and the year ended December 31, 2006. Financial data for the period prior to Petrohawk’s acquisition of Mission has been separated by a bold black line.

F-36

The Company’s financial position, results of operations and cash flows as of and for the periods presented reflect allocations based upon the historical accounts of Mission and in relation to Petrohawk’s acquisitions of Mission and of KCS that are based on the percentage of the Mission and KCS reserves included in the Partnership Properties (See Notes 3, Acquisitions and 4, Oil and Natural Gas Properties for additional information). These allocations are not necessarily indicative of the costs and expenses that would have resulted had the Company been operated as a stand-alone entity.

Throughout the periods covered by the combined financial statements, Petrohawk managed cash through a centralized treasury system including all of the Company’s settlements of revenue and expense transactions and payments made or received on behalf of the Company with third parties. These transactions are reflected as a component of owner’s equity on the combined balance sheets and a component of cash from financing activities in the combined statements of cash flows. Subsequent to completion of the offering, Petrohawk will continue to provide cash management services; however, revenues settled and expenses and costs paid on behalf of the Company will be cash settled on a monthly basis using HK Energy Partners LP bank accounts.

The employees supporting the Company’s operations are employees of Petrohawk. The Company’s combined financial statements include costs allocated by Petrohawk for centralized general and administrative services performed by Petrohawk. Costs allocated to the Company were based on identification of Petrohawk’s resources which directly benefit the Company. All of the allocations are based on assumptions that management believes are reasonable; however, these allocations are not necessarily indicative of the costs and expenses that would have resulted if the Company had been operated as a stand-alone entity. These allocations were historically not settled in cash and resulted in adjustments to owner’s equity.

Use of Estimates

The preparation of the Company’s combined financial statements in conformity with GAAP requires 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 combined 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 and the calculation of the Company’s full cost ceiling test. 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 combined 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 June 30, 2007 and December 31, 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 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

F-37

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 percent.

Costs associated with unevaluated properties are excluded from the full cost pool until we have 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.

Income Taxes

No provision for federal or state income taxes is made in our combined financial statements except for the Texas margin tax which is an income tax assessed at the Company’s level because the taxable income or loss will be included in the income tax returns of the individual partners of the Partnership with the exception of the Texas franchise tax.

A reconciliation between the statutory federal income tax rate and the effective income tax rate as income taxes were included in the financial statements is as follows:

	Six Months Ended
	June 30, 2007		June 30, 2006
Statutory rate	35.0	%	35.0	%
Statutory depletion	124.0		—
State income tax, net of federal benefit	(10.2	)	69.3
Effective tax rate	148.8	%	104.3	%

The following table reconciles net income before income taxes to pro forma federal taxable income for the periods indicated (in thousands, unaudited):

	Six Months Ended
	June 30, 2007			June 30, 2006
Net (loss) income before taxes	$	(579	)	$	576
Depletion, depreciation and amortization for tax reporting purposes		709			(2,233	)
Pro forma federal taxable income (loss)	$	130		$	(1,657	)

The Company’s financial reporting bases of its net assets exceeded the tax bases of its net assets by $374.1 million and $246.0 million at June 30, 2007 and 2006, respectively.

The following table details pro forma net income reflecting a tax provision calculated on a separate return basis (in thousands):

	Six Months Ended
	June 30, 2007			June 30, 2006
Net (loss) income before taxes	$	(579	)	$	576
Tax benefit (provision)		861			(601	)
Pro forma net income (loss)	$	282		$	(25	)

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Revenue Recognition

The Company recognizes oil and natural gas sales upon delivery to the purchaser. Under the sales method, the Company and other joint owners may sell more or less than their entitled share of the natural gas volume produced. Should the Company’s excess sales of natural gas exceed its share of estimated remaining recoverable reserves, a liability is recorded by the Company and revenue is deferred.

Asset Retirement Obligation

SFAS No. 143,Accounting for Asset Retirement Obligations (“FAS 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. The Company has 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. 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 these indicators suggest a material change in the estimated obligations materially changed on an interim basis, 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 (“FAS 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 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 write down is charged against earnings.

Petrohawk’s acquisitions of Mission and KCS generated approximately $130.0 million (of which $76.9 million has been allocated to the Company) and $768.2 million (of which $76.7 million has been allocated to the Company) of goodwill, respectively. The Company’s combined financial statements include an allocation of such goodwill based upon the total goodwill recognized for each individual transaction by Petrohawk at the date of acquisition times the ratio of the estimated proved reserves (volumes) acquired by the Company over the total estimated proved reserves acquired by Petrohawk in such transaction.

The Company completed its annual impairment review during the third quarter of 2006. No impairment was deemed necessary. Downward revisions of estimated proved 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.

Recently Issued Accounting Pronouncements

In February 2007, the FASB issued Statement of Financial Accounting Standards (SFAS) 159,The Fair Value Option for Financial Assets and Financial Liabilities Including an Amendment of FASB Statement No. 115 (“SFAS 159”), which permits entities to choose to measure many financial instruments and certain other items at fair value (the Fair Value Option). Election of the Fair Value Option is made on an instrument-by-instrument

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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 and 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 and cash flows.

3. Acquisitions

Mission Resources Corporation

On July 28, 2005, Mission merged with, and into, Petrohawk. The merger was accounted for using the purchase method of accounting under the accounting standards established in SFAS No. 141,Business Combinations (“FAS 141”) and FAS 142 “Goodwill and Other Intangible Assets.” Petrohawk reflected the results of operations of Mission beginning July 28, 2005. Petrohawk recorded the estimated fair values of the assets acquired and liabilities assumed at July 28, 2005.

In the combined financial statements, the beginning property balance at January 1, 2004 was calculated based upon Mission’s historical oil and gas property balance times the ratio of estimated proved reserves (volumes) of the properties included in the combined financial statements to Mission’s total estimated proved reserves. At the time of the Mission acquisition by Petrohawk, the property balance was revalued to fair value based upon the total acquisition cost of Mission times the ratio of estimated proved reserves (volumes) of the properties included in the combined financial statements to Mission’s total estimated proved reserves. Specific identification was used to allocate unevaluated property balances. Asset retirement obligations resulting from the Mission acquisition were allocated to the Company as of July 28, 2005, based on the specific properties included in the combined financial statements. Petrohawk’s acquisition of Mission generated approximately $130.0 million of Goodwill. The Company’s combined financial statements include an allocation of such goodwill based upon the goodwill recognized for each individual transaction by Petrohawk at the date of acquisition times the ratio of the estimated proved reserves (volumes) acquired by the Company over the total estimated proved reserves acquired by Petrohawk in such transaction.

KCS Energy, Inc.

On July 12, 2006, KCS merged with and into Petrohawk. The merger with KCS was accounted for using the purchase method of accounting under the accounting standards established in FAS 141 and FAS 142. Petrohawk reflected the results of operations of KCS beginning July 12, 2006. Petrohawk recorded the estimated fair values of the assets acquired and liabilities assumed at July 12, 2006.

In the combined financial statements, the Company’s basis in the KCS Properties was calculated as Petrohawk’s total acquisition cost of KCS times the ratio of estimated proved reserves (volumes) of the properties included in the combined financial statements to KCS’ total estimated proved reserves. Specific identification was used to allocate unevaluated property balances. Asset retirement obligations resulting from the KCS acquisition were allocated to the Company as of July 12, 2006, based on the specific properties included in the combined financial statements. Petrohawk’s acquisition of KCS generated approximately $768.2 million of

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goodwill. The Company’s Combined Financial statements include an allocation of such goodwill based upon the total goodwill recognized for each individual transaction by Petrohawk at the date of acquisition times the ratio of the estimated proved reserves (volumes) acquired by the Company over the total estimated proved reserves acquired by Petrohawk in such transaction.

Pro Forma Results of Operations for the Company’s Acquisition of the KCS Properties

The Company’s unaudited pro forma results of operations for the six months ended June 30, 2006 are 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 acquisition of the KCS Properties had been completed on January 1, 2006. The unaudited pro forma results of operations do not purport to represent the actual results of operations had the acquisition in fact occurred on such date or to project the Company’s results of operations for any future date or period.

	For the Six Months Ended June 30, 2006
	(Unaudited)
	(In thousands, except per share data)
Pro forma:
Oil and gas revenues	$	39,930
Net income	$	2,247

4. Oil and Natural Gas Properties

The Company uses the full cost method of accounting for its investment in oil and gas properties. Under this method of accounting, all costs of acquisition, exploration and development of oil and gas reserves (including such costs as leasehold acquisition costs, geological expenditures, dry hole costs, tangible and intangible development costs and direct internal costs) are capitalized as the cost of oil and gas properties when incurred. To the extent that capitalized costs of oil and gas properties, net of accumulated depletion exceed the discounted future net revenues of proved oil and gas reserves net of deferred taxes, such excess capitalized costs would be charged to expense. Full cost companies must use the prices in effect at the end of each accounting quarter to calculate the ceiling test value of their reserves. However, subsequent commodity price increases may be utilized to calculate the ceiling value and reserves. Decreases in product price levels, as well as changes in production rates, levels of reserves, the evaluation of costs excluded from amortization, future development costs, and service costs and other factors could result in significant future ceiling test impairments. Using June 30, 2007 prices, the Company’s net book value of oil and natural gas properties exceeded the ceiling amount by approximately $6.0 million.

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.

5. Long-Term Debt

Petrohawk incurred additional debt in connection with its acquisition of KCS. As a result, Petrohawk debt was allocated to the Company based on the respective percentages of total KCS estimated proved reserves being transferred to the Company.

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The following table presents the components of Petrohawk’s acquisition-related debt that have been allocated to the Company, as of June 30, 2007 and December 31, 2006:

		June 30, 2007		December 31, 2006
		(In thousands)
Senior revolving credit facility		$	115,790	$	115,790
9 1/8% $650mm senior notes(1)			127,453		127,310
7 1/8% $275mm senior notes(2)			26,382		26,237
		$	269,625	$	269,337
	��

(1) Amount includes a $1.4 million and $1.5 million discount recorded by the Company in conjunction with the issuance of the notes as of June 30, 2007 and December 31, 2006, respectively. See “9 ¹/8% Senior Notes” below for more details.

(2) Amount includes a $1.1 million and $1.2 million discount recorded by the Company in conjunction with the assumption of the notes as of June 30, 2007 and December 31, 2006, respectively. See “7 ¹/8% Senior Notes” below for more details.

Senior Revolving Credit Facility

The Company’s combined financial statements include a carve-out of $115.8 million of Petrohawk’s senior revolving credit facility. This allocation was based upon the cash requirements of Petrohawk’s merger with Mission and the ratio of estimated proved reserves acquired by the Company to total estimated proved reserves acquired by Petrohawk in conjunction with Petrohawk’s merger with Mission.

In connection with the Petrohawk’s merger with KCS, Petrohawk 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 Petrohawk’s oil and natural gas properties, reserves, other indebtedness and other relevant factors. At June 30, 2007, the borrowing base was $750 million. On July 25, 2007, Petrohawk executed an amendment to its senior revolving credit facility that permits it to purchase in the open market a maximum of $375 million on the 7 ¹/8% Senior Notes due 2012, also referred to as the 2012 Notes and 9 ¹/8% Senior Notes due 2013, also referred to as the 2013 Notes. On May 8, 2007, Petrohawk entered into an amendment to its senior revolving credit facility that would permit it to refinance the 2012 Notes. Amounts outstanding bear interest at specified margins over LIBOR of 1.00% to 1.75% for Eurodollar loans or at specified margins over ABR of 0.00% to 0.50% for ABR loans. Such margins fluctuate based on the utilization of the facility. Borrowings are secured by first priority liens on substantially all of Petrohawk’s assets and all of the assets of, and equity interest in, the Petrohawk’s subsidiaries. Amounts drawn on the facility will mature on July 12, 2010.

The revolving credit facility contains customary financial and other covenants, including minimum working capital levels, minimum coverage of interest expense, and a maximum leverage ratio. In addition, Petrohawk is subject to covenants limiting dividends and other restricted payments, transactions with affiliates, incurrence of debt, changes of control, asset sales, and liens on properties. At June 30, 2007, Petrohawk was in compliance with all of its debt covenants under the revolving credit facility.

7 ¹/8% Senior Notes

The Company’s combined financial statements include a carve-out allocation of $27.4 million of Petrohawk’s $275 million of 2012 Notes. This allocation was based upon the assumption of these 2012 Notes and the ratio of estimated proved reserves acquired by the Company to Petrohawk’s total estimated proved reserves acquired in conjunction with Petrohawk’s merger with KCS. In addition, the Company’s combined financial statements also include the carve-out of $1.1 million of the overall $13.6 million discount originally recognized in conjunction with the assumption of these notes by Petrohawk as of June 30, 2007.

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Upon effectiveness of Petrohawk’s merger with KCS, Petrohawk assumed (pursuant to the Second Supplemental Indenture relating to the 2012 Notes, and subsidiaries of Petrohawk guaranteed (pursuant to the Third Supplemental Indenture relating to such notes), all the obligations (approximately $275 million) of KCS under the 2012 Notes and the Indenture dated April 1, 2004 (the 2012 Indenture) among KCS, U.S. Bank National Association, as trustee, and the subsidiary guarantors named therein, which governs the terms of the 2012 Notes. Interest on the 2012 Notes is payable semi-annually, on each April 1 and October 1. On or after April 1, 2008, Petrohawk 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, Petrohawk must pay 100% of the principal price, plus a specified premium (expressed as percentages of principal amount) plus accrued and unpaid interest thereon, if any, to the applicable redemption date:

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

The 2012 Indenture contains a provision requiring Petrohawk to offer to purchase the 2012 Notes at 101% of face value in the event of a change of control (as defined in the 2012 Indenture). At June 30, 2007, Petrohawk was in compliance with all of its debt covenants under the 2012 Notes.

In conjunction with the assumption of the 2012 Notes, Petrohawk recorded a discount of $13.6 million to be amortized over the remaining life of the notes utilizing the effective interest rate method. The remaining unamortized discount is $11.6 million at June 30, 2007.

The 2012 Notes are jointly and severally and fully and unconditionally guaranteed on a senior unsecured basis by all of Petrohawk’s subsidiaries. Petrohawk Energy Corporation, the issuer of the 2012 Notes, has no material independent assets or operations apart from the assets and operations of its subsidiaries.

9 ¹/8% Senior Notes

The Company’s combined financial statements include a carve-out allocation of $128.8 million of Petrohawk’s issuance of the first $650 million of 2013 Notes. This allocation was based upon Petrohawk’s issuance of $650 million of these 2013 Notes in conjunction with its merger with KCS, the repayment of $76 million of allocated 9 ⁷/8% Senior Notes discussed below and the ratio of estimated proved reserves acquired by the Company to the Company’s total estimated proved reserves acquired in conjunction with Petrohawk’s merger with KCS. In addition, the Company’s combined financial statements also include the carve-out of $1.4 million of the overall $8.2 million discount originally recognized in conjunction with the issuance of the first $650 million of 9 ¹/8% Senior Notes as of June 30, 2007.

On July 12, 2006 and July 27, 2006, Petrohawk consummated private placements of $650 million and $125 million, respectively, of the 2013 Notes, pursuant to an Indenture dated as of July 12, 2006 (2013 Indenture) and First Supplemental Indenture to the 2013 Notes (the 2013 First Supplemental Indenture), among Petrohawk, Petrohawk’s subsidiaries named therein as guarantors, and U.S. Bank National Association, as trustee. The first tranche of $650 million in 2013 Notes was 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. Petrohawk applied a portion of the net proceeds from the initial sale to fund the cash consideration paid by Petrohawk to the KCS stockholders in connection with Petrohawk’s merger with KCS and Petrohawk’s repurchase of the 9 ⁷/8% Senior Notes due 2011 pursuant to a tender offer Petrohawk concluded in July 2006. The additional $125 million in 2013 Notes were issued pursuant to the same Indenture at 101.125% of the face

F-43

amount. Petrohawk applied the net proceeds from the sale of the additional 2013 Notes to repay indebtedness outstanding under its senior revolving credit facility. The Company’s financial statements do not include a carve-out allocation of this tranche of 2013 Notes as these notes were not issued in conjunction with the acquisition of KCS.

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 Petrohawk and rank equally with all of its current and future senior indebtedness, including the 2012 Notes. The 2013 Notes rank effectively subordinate to Petrohawk’s secured debt to the extent of the collateral, including secured debt under the revolving credit facility, and senior to any future subordinated indebtedness. The 2013 Notes are jointly and severally and fully and unconditionally guaranteed on a senior unsecured basis by all of Petrohawk’s subsidiaries. Petrohawk Energy Corporation, the issuer of the 2013 Notes, has no material independent assets or operations apart from the assets and operations of its subsidiaries.

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

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

On or after July 15, 2010, Petrohawk 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, Petrohawk 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

Petrohawk 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, Petrohawk 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 Petrohawk 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 Petrohawk’s assets. Additionally, the 2013 Indenture covering the 2013 Notes contains a provision which provides for a rate increase of 1/8 of one percent if Petrohawk refinances any part of its 2012 Notes on or before July 11, 2007.

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

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

9 ⁷/8% Senior Notes

The Company’s combined financial statements include a carve-out allocation of $76.9 million of Petrohawk’s total $130 million 2011 Notes. This allocation was based upon Petrohawk’s assumption of the 2011 Notes in conjunction with its merger with Mission and the ratio of estimated proved reserves acquired by the Company to the Company’s total estimated proved reserves acquired. In addition, the Company’s combined financial statements also include the carve-out of $6.6 million of the overall $11.1 million premium originally recognized in conjunction with the assumption of the 2011 Notes. The 2011 Notes were substantially extinguished in conjunction with the Company’s merger with KCS.

On April 8, 2004, Mission Resources Corporation issued $130.0 million of its 9 ⁷/8% Senior Notes due 2011 (the “2011 Notes”). Petrohawk assumed these notes upon the closing of its merger with Mission. In conjunction with Petrohawk’s merger with KCS, Petrohawk extinguished substantially all of its 2011 Notes for a premium of $14.9 million plus accrued interest of $3.5 million. There were approximately $0.3 million of the notes which were not redeemed and were still outstanding as of June 30, 2007. In connection with the extinguishment of substantially all of the 2011 Notes, Petrohawk requested and received from the noteholders consent to eliminate most significant debt covenants associated with the 2011 Notes.

Debt Issuance Costs

The Company capitalizes certain direct costs associated with the issuance of long-term debt. The combined financial statements reflect an allocation of a portion of debt issue costs based upon the ratio of the estimated proved reserves (volumes) of the properties acquired in such acquisition that are included in the combined financial statements to Mission’s and KCS’ respective total estimated proved reserves for each acquisition. At June 30, 2007 and December 31, 2006, the Company had approximately $2.3 million and $2.5 million of net debt issuance costs being amortized over the lives of the respective debt.

6. 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 an asset retirement obligation liability (“ARO”) on the combined 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.

F-45

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

Liability for asset retirement obligation as of January 1, 2007	$	6,394
Liabilities settled and divested		—
Additions		13
Acquisitions		—
Accretion expense		172
Liability for asset retirement obligation as of June 30, 2007	$	6,579

7. 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 the Company’s business. All known liabilities are accrued based on the Company’s best estimate of the potential loss. At June 30, 2007 the Company is not involved in any legal proceedings that individually or in the aggregate could have a material adverse effect on the Company’s consolidated financial position, results of operations or cash flow.

F-46

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Owners of HK Energy Partners LP Predecessor

Houston, Texas

We have audited the accompanying statements of revenues less direct operating expenses — assets acquired from KCS Energy, Inc. (the “KCS Properties”), as defined in the merger agreement dated April 21, 2006 by and between Petrohawk Energy Corporation (the “Parent”) and KCS Energy, Inc., for the period from January 1, 2006 to July 11, 2006, and for each of the years ended December 31, 2005 and 2004. These statements are the responsibility of the Parent’s management. Our responsibility is to express an opinion on these statements 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 statement is free of material misstatement. The KCS Properties are not required to have, nor were we engaged to perform, an audit of their internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the KCS Properties internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes 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, as well as evaluating the overall statement presentation. We believe that our audits provide a reasonable basis for our opinion.

The accompanying statements were prepared for the purpose of complying with the rules and regulations of the Securities and Exchange Commission as described in Note 1 to the statement and are not intended to be a complete presentation of the Parent’s interests in the KCS Properties described above.

In our opinion, the statements referred to above presents fairly, in all material respects, the revenues and direct operating expenses of the KCS Properties for the period from January 1, 2006 to July 11, 2006 and for each of the years ended December 31, 2005 and 2004, as described in Note 1 to the statements, in conformity with accounting principles generally accepted in the United States of America.

/s/ Deloitte & Touche LLP

Houston, Texas

October 29, 2007

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KCS PROPERTIES

STATEMENTS OF REVENUES LESS DIRECT OPERATING EXPENSES -

ASSETS ACQUIRED FROM KCS ENERGY, INC.

(in thousands)

	Period January 1, 2006 to July 11, 2006		Year Ended December 31, 2005		Year Ended December 31, 2004
Operating revenues:
Oil and gas	$	18,707	$	36,107	$	28,733
Direct operating expenses:
Production:
Lease operating		1,634		3,401		3,001
Workover and other		49		53		230
Taxes other than income		1,861		3,036		2,760
Gathering, transportation and other		605		1,066		937
Total operating expenses		4,149		7,556		6,928
Revenues less direct operating expenses	$	14,558	$	28,551	$	21,805

See notes to the statements of revenues less direct operating expenses.

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KCS PROPERTIES

ASSETS ACQUIRED FROM KCS ENERGY, INC.

NOTES TO STATEMENTS OF REVENUES LESS DIRECT OPERATING EXPENSES

Note 1. Basis of Presentation

The accompanying historical statements of revenues less direct operating expenses presents the revenues less direct operating expenses of the assets (the “KCS Properties”) acquired, as defined in the merger agreement dated April 21, 2006, between KCS Energy, Inc. (“KCS”) and Petrohawk Energy Corporation (“Petrohawk”), for the period from January 1, 2006 to July 11, 2006 and for the years ended December 31, 2006 and 2005. The merger was consummated on July 12, 2006.

The KCS Properties were part of a larger affiliated enterprise prior to their acquisition by Petrohawk, and representative amounts of general and administrative expenses, depreciation, depletion and amortization, interest and other indirect costs were not allocated to the properties acquired, nor would such allocated historical costs be relevant to future operations of the KCS Properties. Accordingly, the historical statements of revenues less direct operating expenses are presented in lieu of the full financial statements required under Item 3-05 of Securities and Exchange Commission Regulation S-X.

Revenues in the accompanying statements of revenues less direct operating expenses are recognized on the sales method. Under this method of accounting, revenues are recognized based on volumes sold, which may differ from the volume to which the Partnership is entitled based on the its working interest. An imbalance is recognized as a liability only when the estimated remaining reserves will not be sufficient to enable the under-produced owner(s) to recoup its entitled share through future production. Direct operating expenses are recognized on the accrual basis and consist of monthly operator overhead costs and other direct costs of operating the KCS Properties. Included in direct operating expenses are costs associated with field operating expenses, marketing, monthly operator overhead, production taxes and ad valorem taxes.

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Note 2. Omitted Historical Financial Information

Historical financial information reflecting financial position, results of operations, and cash flows of the KCS Properties is not presented because it would be impractical and costly to obtain since such financial information was not historically prepared by KCS at a level representative of these properties. Other assets acquired and liabilities assumed were not material. In addition, the KCS Properties were a part of a larger enterprise prior to the acquisition by Petrohawk, and representative amounts of indirect general and administrative expenses, depreciation, depletion and amortization, interest and other indirect costs were not necessarily allocated to the KCS Properties acquired, nor would such allocated historical costs be relevant to future operations of the KCS Properties. The historical statements of revenues less direct operating expenses of Petrohawk’s interest in the KCS Properties are presented in order to substantially comply with the rules and regulations of the Securities and Exchange Commission for businesses acquired. Accordingly, the accompanying statements are presented in lieu of the financial statements required under Rule 3-05 of Securities and Exchange Commission Regulation S-X.

Note 3. Commitments and Contingencies

Pursuant to the terms of the related merger agreement, any claims, litigation or disputes pending as of the effective date (July 12, 2006) or any matters arising in connection with ownership of the KCS Properties prior to the effective date were assumed by Petrohawk. The Company is not aware of any legal, environmental or other commitments or contingencies that would have a material effect on the statement of revenues less direct operating expenses.

F-49

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 total 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, 2005 and 2004 and January 1, 2004 were audited by Netherland, Sewell & Associates, Inc., the Company’s independent consulting petroleum engineers. These estimates of proved reserves have been made in accordance with SEC guidelines using constant oil and natural gas prices. All proved reserves are located in the United States of America.

F-50

SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)

(CONTINUED)

The following table illustrates estimated net proved reserves, including changes, and proved developed reserves of the KCS Properties for the periods indicated. Natural gas liquids are included in natural gas.

	Proved Reserves
	Oil (MBbls)		Gas (MMcf)		Equivalent(1) (MMcfe)
Proved reserves, January 1, 2004	70		47,956		48,376
Extensions and discoveries	—		—		—
Purchase of minerals in place	—		—		—
Production	(8	)	(4,371	)	(4,420	)
Revision of previous estimates	5		6,372		6,405
Proved reserves, December 31, 2004	67		49,957		50,361
Extensions and discoveries	—		—		—
Purchase of minerals in place	—		—		—
Production	(9	)	(4,244	)	(4,299	)
Sale of minerals in place	—		—		—
Revision of previous estimates	21		6,468		6,593
Proved reserves, December 31, 2005	79		52,181		52,655

	Proved Developed Reserves
	Oil (MBbls)	Gas (MMcf)	Equivalent (MMcfe)
December 31, 2004	66	40,136	40,531
December 31, 2005	77	39,312	39,776

(1) Calculated using natural gas equivalents of six Mcf of natural gas per Bbl of oil or NGL. NGLs are included in natural gas.

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 Petrohawk’s engineering staff. It can be used for some comparisons, but should not be the only method used to evaluate the Partnership 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 Flows be viewed as representative of the current value of the KCS Properties.

Petrohawk 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; and

• 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.

F-51

SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)

(CONTINUED)

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. 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 is required by SFAS 69.

The Standardized Measure is as follows:

	Years Ended December 31,
	2005			2004
	(in thousands)
Future cash inflows	$	440,319		$	327,647
Future production costs		(163,046	)		(120,308	)
Future development costs		(23,177	)		(16,668	)
Future net cash flows before 10% discount		254,096			190,671
10% annual discount for estimated timing of cash flows		(117,101	)		(86,987	)
Standardized measure of discounted future net cash flows	$	136,995		$	103,684

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 proved oil and natural gas reserves during the periods ending December 31, 2005, and 2004.

	Year Ended December 31,
	2005			2004
	(in thousands)
Beginning of year	$	103,684		$	100,465
Sale of oil and gas produced, net of production costs		(28,475	)		(21,635	)
Changes in prices and production costs		28,461			(9,076	)
Changes in future development costs		(7,512	)		(6,447	)
Development costs incurred		7,425			11,695
Revisions of previous quantities		17,171			12,755
Accretion of discount		10,368			10,047
Changes in production rates and other		5,873			5,880
End of year	$	136,995		$	103,684

F-52

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Partners of

HK Energy Partners LP

Houston, Texas

We have audited the accompanying balance sheet of HK Energy Partners LP (the “Partnership”) as of October 24, 2007. This financial statement is the responsibility of the Partnership’s management. Our responsibility is to express an opinion on this financial statement based on our audit.

We conducted our audit in accordance with auditing 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 balance sheet is free of material misstatement. The Partnership is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the balance sheet, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall balance sheet presentation. We believe that our audit of the balance sheet provides a reasonable basis for our opinion.

In our opinion, such balance sheet presents fairly, in all material respects, the financial position of the Partnership as of October 24, 2007 in conformity with accounting principles generally accepted in the United States of America.

DELOITTE & TOUCHE LLP

Houston, Texas

October 29, 2007

F-53

HK Energy Partners LP

BALANCE SHEET

October 24, 2007

ASSETS
Current assets
Cash	$	1,000
Total assets	$	1,000
PARTNERS’ CAPITAL
Partners’ capital
Limited partners’ equity	$	980
General partner’s equity		20
Total partners’ capital	$	1,000

See note to balance sheet.

F-54

HK Energy Partners LP

NOTE TO BALANCE SHEET

1. Nature of Operations

HK Energy Partners LP (the “Partnership”) is a Delaware limited partnership formed in October 2007, to acquire the assets of HK Energy Partners LP Predecessor. The Partnership’s general partner is HK Energy Partners GP LP.

The Partnership intends to offer 9,250,000 common units, representing limited partner interests, pursuant to a public offering and to concurrently issue 5,904,048 additional common units and 5,189,742 subordinated units, also representing additional limited partner interests, to subsidiaries of Petrohawk, and a 2% general partner interest and all of its incentive distribution rights to HK Energy Partners GP LP.

HK Energy Partners GP LP, as general partner, contributed $20 and Petrohawk, on behalf of HKE Holdings LLC for its limited partner interest, contributed $980 to the Partnership in October 2007. There have been no other transactions involving the Partnership.

F-55

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Partners of

HK Energy Partners GP LP

Houston, Texas

We have audited the accompanying balance sheet of HK Energy Partners GP LP (the “Partnership”) as of October 24, 2007. This financial statement is the responsibility of the Partnership’s management. Our responsibility is to express an opinion on this financial statement based on our audit.

We conducted our audit in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the balance sheet is free of material misstatement. An audit includes consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the balance sheet, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall balance sheet presentation. We believe that our audit of the balance sheet provides a reasonable basis for our opinion.

In our opinion, such balance sheet presents fairly, in all material respects, the financial position of the Partnership at October 24, 2007, in conformity with accounting principles generally accepted in the United States of America.

DELOITTE & TOUCHE LLP

Houston, Texas

October 29, 2007

F-56

HK ENERGY PARTNERS GP LP

BALANCE SHEET

October 24, 2007

ASSETS
Current assets
Cash	$	990
Investment in HK Energy Partners LP		10
Total assets	$	1,000
PARTNERS’ CAPITAL
Partners’ capital
Limited partner’s equity	$	990
General partner’s equity		10
Total partners’ capital	$	1,000

See note to financial statement

F-57

HK Energy Partners GP LP

NOTE TO BALANCE SHEET

1. Nature of Operations

HK Energy Partners GP LP (“General Partner”) is a Delaware limited partnership, formed in August 2007, to become the general partner of HK Energy Partners LP (“Partnership”). The General Partner is an indirect wholly-owned subsidiary of Petrohawk Energy Corporation. The General Partner owns a 2% general partner interest in the Partnership.

In October 2007, Petrohawk Energy Corporation and its subsidiaries contributed $1,000 to the General Partner in exchange for a 100% ownership interest.

The General Partner has invested $20 in the Partnership. There have been no other transactions involving the General Partner.

F-58

APPENDIX A

FIRST AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP

OF HK ENERGY PARTNERS LP

[TO BE FILED BY AMENDMENT]

A-1

APPENDIX B

GLOSSARY OF TERMS

Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.

Bbl/d. One Bbl per day.

Bcf. One billion cubic feet of natural gas.

Bcfe. One billion cubic feet equivalent calculated by converting one Bbl of oil or NGLs to six Mcf of natural gas.

Btu. British thermal unit, which is the heat required to raise the temperature of a one pound mass of water from 58.5 to 59.5 degrees Fahrenheit.

Development Drilling. A well drilled within the proved area of an oil or natural gas reservoir, or which extends a proved reservoir, to the depth of a stratigraphic horizon known to be productive.

Downspacing. Additional wells drilled between known producing wells to better exploit the reservoir.

Dry Hole. A well found to be incapable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well.

Exploratory Well. A well drilled to find and produce oil or natural gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir, or to extend a known reservoir.

GAAP. Accounting principles that are generally accepted in the United States of America.

Horizontal Drilling. Drilling wells at angles greater than 70 degrees from vertical.

Infill. Development wells drilled to fill in between established producing wells.

MBbl. One thousand stock tank barrels.

Mcf. One thousand cubic feet of natural gas.

Mcf/d. One Mcf per day

Mcfe. One thousand cubic feet equivalent calculated by converting one Bbl of oil or NGLs to six Mcf of natural gas.

MMBbls. One million stock tank barrels.

MMBtu. One million British thermal units.

MMcf. One million cubic feet of natural gas.

MMcfe. One million cubic feet equivalent calculated by converting one Bbl of oil or NGLs to six Mcf of natural gas.

B-1

MMcfe/d. One million cubic feet equivalent per day.

NGLs. The combination of ethane, propane, butane and natural gasolines that when removed from natural gas become liquid under various levels of higher pressure and lower temperature.

NYMEX. New York Mercantile Exchange.

Oil. Crude oil and condensate.

Proved Developed Reserves. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and natural gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

Proved Reserves. The estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.

Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any, and (B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.

Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the proved classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

Proved Undeveloped Reserves. Reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

Tcf. One trillion cubic feet of natural gas.

Tcfe. One trillion cubic feet equivalent calculated by converting one Bbl of oil or NGLs to six Mcf of natural gas.

Working Interest. The operating interest that gives the owner the right to drill, produce and conduct activities on the property and a share of production

Workover. Operations on a producing well to restore or increase production.

B-2

APPENDIX C

JUNE 30, 2007 REPORT OF NETHERLAND, SEWELL & ASSOCIATES, INC.

October 15, 2007

Mr. Floyd C. Wilson

Petrohawk Energy Corporation

1000 Louisiana Street, Suite 5810

Houston, Texas 77002

Dear Mr. Wilson:

In accordance with your request, we have estimated the proved reserves and future revenue, as of June 30, 2007, to the interest of Petrohawk Energy Corporation and its subsidiaries (collectively referred to herein as “Petrohawk”) in selected oil and gas properties located in the United States. It is our understanding that Petrohawk is considering transferring this interest to a to-be-formed Master Limited Partnership, HK Energy Partners LP. This report has been prepared using constant prices and costs, as discussed in subsequent paragraphs of this letter. The estimates of reserves and future revenue in this report have been prepared in accordance with the definitions and guidelines of the U.S. Securities and Exchange Commission and, with the exception of the exclusion of future income taxes, conform to the Statement of Financial Accounting Standards No. 69. Definitions are presented immediately following this letter.

We estimate the net reserves and future net revenue to the Petrohawk interest in these properties, as of June 30, 2007, to be:

	Net Reserves			Future Net Reveune ($)
Category	Oil (Barrels)	NGL (Barrels)	Gas (MCF)	Total	Present Worth at 10%
Proved Developed
Producing	5,399,811	3,537,315	54,129,792	567,538,2000	274,607,000
Non-Producing	118,881	653,568	3,044,414	26,281,600	7,637,700
Proved Undeveloped	1,247,712	1,092,750	15,789,723	107,572,900	35,289,400
Total Proved	6,766,404	5,283,633	72,963,929	701,392,700	317,534,100

The oil reserves shown include crude oil and condensate. Oil and natural gas liquids (NGL) volumes are expressed in barrels that are equivalent to 42 United States gallons. Gas volumes are expressed in thousands of cubic feet (MCF) at standard temperature and pressure bases.

The estimates shown in this report are for proved developed producing, proved developed non-producing, and proved undeveloped reserves. Our estimates do not include any probable or possible reserves that may exist for these properties. This report does not include any value that could be attributed to interests in undeveloped acreage beyond those tracts for which undeveloped reserves have been estimated. Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status. The estimates of reserves and future revenue included herein have not been adjusted for risk.

C-1

Future gross revenue to the Petrohawk interest is prior to deducting state production taxes and ad valorem taxes. Future net revenue is after deductions for these taxes, future capital costs, and operating expenses but before consideration of federal income taxes. The future net revenue has been discounted at an annual rate of 10 percent to determine its present worth. The present worth is shown to indicate the effect of time on the value of money and should not be construed as being the fair market value of the properties.

For the purposes of this report, we did not perform any field inspection of the properties, nor did we examine the mechanical operation or condition of the wells and their related facilities. We have not investigated possible environmental liability related to the properties; therefore, our estimates do not include any costs due to such possible liability. Also, our estimates do not include any salvage value for the lease and well equipment or the cost of abandoning the properties.

Oil and NGL prices used in this report are based on regional posted prices in effect on June 30, 2007, and are adjusted by lease for quality, transportation fees, and infield price differentials. Gas prices used in this report are based on regional spot market prices in effect on June 30, 2007, and are adjusted by lease for energy content, transportation fees, and infield price differentials. As a reference, the June 30, 2007, Plains Marketing, L.P. West Texas Intermediate posted price was $67.25 per barrel and the June 30, 2007, Platts Henry Hub spot market price was $6.795 per MMBTU. All prices are held constant throughout the lives of the properties.

Lease and well operating costs used in this report are based on operating expense records of Petrohawk. As requested, these costs include direct lease- and field-level costs and Petrohawk’s estimate of the portion of its headquarters general and administrative overhead expenses necessary to operate the properties. For nonoperated properties, these costs also include the per-well overhead expenses allowed under joint operating agreements. Lease and well operating costs are held constant in accordance with SEC guidelines. Capital costs are included as required for workovers, recompletions, new development wells, and production equipment.

We have made no investigation of potential gas volume and value imbalances resulting from overdelivery or underdelivery to the Petrohawk interest. Therefore, our estimates of reserves and future revenue do not include adjustments for the settlement of any such imbalances; our projections are based on Petrohawk receiving its net revenue interest share of estimated future gross gas production.

The reserves shown in this report are estimates only and should not be construed as exact quantities. The reserves may or may not be recovered; if they are recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts. Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions made while preparing this report. Also, estimates of reserves may increase or decrease as a result of future operations.

In evaluating the information at our disposal concerning this report, we have excluded from our consideration all matters as to which the controlling interpretation may be legal or accounting, rather than engineering and geologic. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geologic data; therefore, our conclusions necessarily represent only informed professional judgment.

The titles to the properties have not been examined by Netherland, Sewell & Associates, Inc., nor has the actual degree or type of interest owned been independently confirmed. The data used in our estimates were obtained from Petrohawk Energy Corporation, other interest owners, various operators of the properties, public data sources, and the nonconfidential files of Netherland, Sewell & Associates, Inc. and were accepted as accurate. Supporting geologic, field performance, and work data are on file in our office. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties and are not employed on a contingent basis.

C-2

Sincerely NETHERLAND, SEWELL & ASSOCIATES, INC.
By:	/S/    FREDERIC D. SEWELL, P.E.
	Frederic D. Sewell, P.E. Chairman and Chief Executive Officer

By:	/S/    THOMAS J. TELLA II	By:	/S/    WILLIAM J. KNIGHTS
	Thomas J. Tella II Senior Vice President		William J. Knights Vice President
Date Signed: October 15, 2007		Date Signed: October 15, 2007

C-3

9,250,000 Common Units

Representing Limited Partner Interests

PROSPECTUS

                    , 2007

LEHMAN BROTHERS

WACHOVIA SECURITIES

PART II

INFORMATION NOT REQUIRED IN THE PROSPECTUS

Item 13. Other Expenses of Issuance and Distribution.

Set forth below are the expenses (other than underwriting discounts and commissions) expected to be incurred in connection with the issuance and distribution of the securities registered hereby. With the exception of the Securities and Exchange Commission registration fee, the Financial Industry Regulatory Authority filing fee and The New York Stock Exchange listing fee, the amounts set forth below are estimates.

SEC Registration Fee	$	6,532
FINRA Filing Fee		21,775
NYSE Listing Fee		150,000
Printing and Engraving Expenses		*
Fees and Expenses of Legal Counsel		*
Accounting Fees and Expenses		*
Reservoir Engineering Fees and Expenses		*
Transfer Agent and Registrar Fees		*
Miscellaneous		*
Total	$	*

* To be provided by amendment.

Item 14. Indemnification of Directors and Officers.

The section of the Prospectus entitled “The Partnership Agreement—Indemnification” discloses that we will generally indemnify officers, directors and affiliates of our general partner and its general partner to the fullest extent permitted by the law against all losses, claims, damages or similar events and is incorporated herein by this reference. Any underwriting agreement entered into pursuant to which we sell securities offered in this registration statement will provide for indemnification of the underwriters against certain liabilities, including liabilities under the Securities Act of 1933, and our contribution to payments that may be required to be made in respect of these liabilities. Subject to any terms, conditions or restrictions set forth in the Partnership Agreement, Section 17-108 of the Delaware Revised Uniform Limited Partnership Act empowers a Delaware limited partnership to indemnify and hold harmless any partner or other persons from and against all claims and demands whatsoever.

Item 15. Recent Sales of Unregistered Securities.

HK Energy Partners LP issued to HK Energy Partners GP LP a 2% general partner interest in the partnership in exchange for a capital contribution in the amount of $20 and to HKE Holdings LLC a 98% limited partner interest in the partnership in exchange for a capital contribution in the amount of $980 in connection with the formation of the partnership in October 2007 in an offering exempt from registration under Section 4(2) of the Securities Act of 1933. There have been no other sales of unregistered securities within the past three years.

II-1

Item 16. Exhibits and Financial Statement Schedules.

(a) The following documents are filed as exhibits to this registration statement:

Exhibit
1.1*	—	Form of Underwriting Agreement
3.1	—	Certificate of Limited Partnership of HK Energy Partners LP
3.2*	—	Form of First Amended and Restated Agreement of Limited Partnership of HK Energy Partners LP (incorporated by reference to Appendix A to the Prospectus)
3.3	—	Certificate of Limited Partnership of HK Energy Partners GP LP
3.4*	—	Form of Agreement of Limited Partnership of HK Energy Partners GP LP
3.5	—	Certificate of Formation of Petrohawk Management Company, LLC
3.6*	—	Form of Limited Liability Company Agreement of Petrohawk Management Company, LLC
4.1*	—	Specimen unit certificate for the common units
5.1*	—	Opinion of Thompson & Knight LLP as to the legality of the securities being registered
8.1*	—	Opinion of Thompson & Knight LLP relating to tax matters
10.1*	—	Form of Credit Facility
10.2*	—	Form of Contribution Agreement
10.3*	—	Form of Administrative Services Agreement
10.4*	—	Form of Petrohawk Management Company, LLC Long-Term Incentive Plan
21.1*	—	List of Subsidiaries
23.1	—	Consent of Deloitte & Touche LLP
23.2*	—	Consent of Thompson & Knight LLP (contained in Exhibit 5.1)
23.3*	—	Consent of Thompson & Knight LLP (contained in Exhibit 8.1)
23.4	—	Consent of Netherland, Sewell & Associates, Inc.
24.1	—	Powers of attorney (contained on page II-4)

* To be filed by amendment.

II-2

Item 17. Undertakings.

The undersigned registrant hereby undertakes to provide to the underwriters at the closing specified in the underwriting agreement certificates in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser.

Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of the registrant pursuant to the provisions described in Item 14, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

The undersigned registrant hereby undertakes that:

(1) For purposes of determining any liability under the Securities Act, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this registration statement as of the time it was declared effective.

(2) For the purpose of determining any liability under the Securities Act, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

The registrant undertakes to send to each limited partner at least on an annual basis a detailed statement of any transactions with Petrohawk Management Company, LLC or its affiliates, and of fees, commissions, compensation and other benefits paid or accrued to Petrohawk Management Company, LLC or its affiliates for the fiscal year completed, showing the amount paid or accrued to each recipient and the services performed.

The registrant undertakes to provide to the limited partners the financial statements required by Form 10-K for the first full fiscal year of operations of the partnership.

II-3

SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, as amended, the registrant has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Houston, State of Texas, on October 30, 2007.

HK Energy Partners LP
By:	HK Energy Partners GP LP Its General Partner
By:	Petrohawk Management Company, LLC Its General Partner
By:	/s/ Floyd C. Wilson
Name:	Floyd C. Wilson
Title:	President and Chief Executive Officer

Each person whose signature appears below appoints Floyd C. Wilson and Mark J. Mize and each of them, any of whom may act without the joinder of the other, as the undersigned’s true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, for the undersigned and in the undersigned’s name, place and stead, in any and all capacities, to sign any and all amendments (including post-effective amendments) to this Registration Statement and any Registration Statement (including any amendment thereto) for this offering that is to be effective upon filing pursuant to Rule 462(b) under the Securities Act of 1933 and to file the same, with all exhibits thereto, and all other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents full power and authority to do and perform each and every act and thing requisite and necessary to be done, as fully to all intents and purposes as the undersigned might or would do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents or any of them of their or the undersigned’s substitute and substitutes, may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Act of 1933, this registration statement has been signed by the following persons in the capacities and on the dates indicated.

Signature	Title	Date
/s/    FLOYD C. WILSON         Floyd C. Wilson	Chairman, President and Chief Executive Officer (Principal Executive Officer and Director)	October 30, 2007
/s/    MARK J. MIZE         Mark J. Mize	Executive Vice President — Chief Financial Officer and Treasurer (Principal Financial and Accounting Officer)	October 30, 2007

II-4

INDEX TO EXHIBITS

Exhibit
1.1	*	—	Form of Underwriting Agreement
3.1		—	Certificate of Limited Partnership of HK Energy Partners LP
3.2	*	—	Form of First Amended and Restated Agreement of Limited Partnership of HK Energy Partners LP (incorporated by reference to Appendix A to the Prospectus)
3.3		—	Certificate of Limited Partnership of HK Energy Partners GP LP
3.4	*	—	Form of Agreement of Limited Partnership of HK Energy Partners GP LP
3.5		—	Certificate of Formation of Petrohawk Management Company, LLC
3.6	*	—	Form of Limited Liability Company Agreement of Petrohawk Management Company, LLC
4.1	*	—	Specimen unit certificate for the common units
5.1	*	—	Opinion of Thompson & Knight LLP as to the legality of the securities being registered
8.1	*	—	Opinion of Thompson & Knight LLP relating to tax matters
10.1	*	—	Form of Credit Facility
10.2	*	—	Form of Contribution Agreement
10.3	*	—	Form of Administrative Services Agreement
10.4	*	—	Form of Petrohawk Management Company, LLC Long-Term Incentive Plan
21.1	*	—	List of Subsidiaries
23.1		—	Consent of Deloitte & Touche LLP
23.2	*	—	Consent of Thompson & Knight LLP (contained in Exhibit 5.1)
23.3	*	—	Consent of Thompson & Knight LLP (contained in Exhibit 8.1)
23.4		—	Consent of Netherland, Sewell & Associates, Inc.
24.1		—	Powers of attorney (contained on page II-4)

* To be filed by amendment.