Grizzly Energy S1/A IPO registration (amended)

Grizzly Energy (GRZZP) Inactive S-1/AIPO registration (amended)

As filed with the Securities and Exchange Commission on September 18, 2007

Registration No. 333-142363

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Amendment No. 4
to
FORM S-1

REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933

Vanguard Natural Resources, LLC

(Exact name of registrant as specified in its charter)

Delaware		1311		61-1521161
(State or other jurisdiction of incorporation or organization)		(Primary Standard Industrial Classification Code Number)		(I.R.S. Employer Identification Number)

7700 San Felipe, Suite 485

Houston, Texas 77063

(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices)

Scott W. Smith

Vanguard Natural Resources, LLC

7700 San Felipe, Suite 485

Houston, Texas 77063

(832) 327-2255

(Name, address, including zip code, and telephone number, including area code, of agent for service)

Copies to:

David P. Oelman
Douglas E. McWilliams
Vinson & Elkins L.L.P.
First City Tower
1001 Fannin, Suite 2300
Houston, Texas 77002
(713) 758-2222

G. Michael O’Leary
Andrews Kurth LLP
600 Travis Street, Suite 4200
Houston, Texas 77002
(713) 220-4200

Approximate date of commencement of proposed sale to the public: As soon as practicable after this Registration Statement becomes effective.

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

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. o

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. o

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. o

If delivery of the prospectus is expected to be made pursuant to Rule 434, please check the following box. 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.

Subject to completion, dated September 18, 2007

The information in this 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 prospectus is not an offer to sell these securities and is not soliciting an offer to buy these securities in any state where the offer or sale is not permitted.

PROSPECTUS

5,000,000 Common Units
Representing Limited Liability Company Interests

This is the initial public offering of our common units. We are selling 5,000,000 common units representing limited liability company interests in us. We expect the initial public offering price to be between $22.00 and $24.00 per common unit. Prior to this offering, there has been no public market for our common units. Our common units have been approved for listing, subject to official notice of issuance, on NYSE Arca under the symbol “VNR.”

Investing in our common units involves risks. Please read “Risk Factors” beginning on page 20.

These risks include the following:

· We may not have sufficient cash from operations to pay the initial quarterly distribution on our common units following establishment of cash reserves and payment of fees and expenses.

· We intend to rely on Vinland Energy Eastern, LLC, or Vinland, an affiliate of our largest beneficial owner, Majeed S. Nami, to execute our drilling program. If Vinland 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 to our unitholders.

· Natural gas and oil prices are volatile, and if commodity prices decline significantly for a temporary or prolonged period, our cash flow from operations may decline and we may have to lower our distributions or may not be able to pay distributions at all.

· Unless we replace our reserves, our existing reserves and production will decline, which would adversely affect our cash flow from operations and our ability to make distributions to our unitholders.

· Vinland controls our drilling program. Vinland has agreed to drill not less than 100 gross wells per calendar year through January 5, 2011. If Vinland drills only its minimum commitment, our total production is expected to decline by an average of approximately 2.7% per year for the three-year period beginning March 31, 2007.

· We are exposed to the credit risk of Vinland and any material nonperformance by Vinland could reduce our ability to make distributions to our unitholders.

· Our operations 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 reserves and affect our ability to make distributions to our unitholders.

· We rely on Vinland Energy Gathering, LLC, an affiliate of Mr. Nami, to gather and deliver our natural gas to certain designated interconnects with third-party transporters. Any limitation in these services or delay in providing interconnections to newly drilled wells would interfere with our ability to market the natural gas we produce and could reduce our revenues and cash available for distribution.

· We may incur substantial additional debt in the future to enable us to pursue our business plan and to pay distributions to our unitholders.

· Mr. Nami, who together with certain of his affiliates and related persons, will own approximately 29.7% of our outstanding units after this offering, and certain members of our board of directors who are officers or directors of Vinland may have conflicts of interest with us. The ultimate resolution of these conflicts of interest may result in favoring the interests of these other parties over yours and may be to our detriment. Our limited liability company agreement limits the remedies available to you in the event you have a claim relating to conflicts of interest.

· You will experience immediate and substantial dilution of $14.45 per common unit.

· You may be required to pay taxes on income from us even if you do not receive any cash distributions from us.

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.

	Per Common Unit		Total
Public offering price		$		$
Underwriting discount(1)		$		$
Net Proceeds to Vanguard Natural Resources, LLC (before expenses)		$		$

(1) Excludes structuring fee of approximately $0.4 million. Please read “Underwriting” for more information.

The underwriters expect to deliver the common units on or about , 2007. We have granted the underwriters a 30-day option to purchase up to an additional 750,000 common units on the same terms and conditions as set forth above if the underwriters sell more than 5,000,000 common units in this offering.

Citi

, 2007

TABLE OF CONTENTS

Prospectus Summary		1
Vanguard Natural Resources, LLC		1
Business Strategies		3
Competitive Strengths		3
Our Relationship with Vinland		4
Cash Distribution Policy		5
Summary of Risk Factors		5
Private Placement		7
Reserve-Based Credit Facility		7
Our LLC Structure		7
Organizational Structure		9
The Offering		10
Summary Historical and Pro Forma Consolidated Financial And Operating Data		14
Summary Reserve and Operating Data		17
Non-GAAP Financial Measure		19
Risk Factors		20
Risks Related to Our Business		20
Risks Related to Our Structure		35
Tax Risks to Unitholders		38
Cautionary Note Regarding Forward-Looking Statements		41
Use of Proceeds		42
Capitalization		43
Dilution		44
Cash Distribution Policy and Restrictions on Distributions		45
General		45
Our Initial Quarterly Distribution Rate		47
Financial Forecast		48
Estimated Cash Available to Pay Distributions		49
Assumptions and Considerations		52
Sensitivity Analysis		56
Unaudited Pro Forma Cash Available to Pay Distributions		57
How We Make Cash Distributions		60
Distributions of Available Cash		60
Definition of Available Cash		60
Distributions of Cash Upon Liquidation		60
Adjustments to Capital Accounts		60
Selected Historical and Pro Forma Consolidated Financial Data		61
Management’s Discussion and Analysis of Financial Condition and Results of Operations		64
Overview		64
Nami Restructuring Plan.		66
Private Offering		66
Reserve-Based Credit Facility.		66
Outlook		66
Comparability of Financial Statements		68
Results of Operations		69
Six Months Ended June 30, 2007 Compared to Six Months Ended June 30, 2006		70
Year Ended December 31, 2006 Compared to Year Ended December 31, 2005		72
Year Ended December 31, 2005 Compared to Year Ended December 31, 2004		73
Capital Resources and Liquidity		74
Cash Flow from Operations		75
Investing Activities—Acquisitions and Capital Expenditures		76
Financing Activities		76

Quantitative and Qualitative Disclosure About Market Risk	79
Critical Accounting Policies and Estimates	79
Full-Cost Method of Accounting for Natural Gas and Oil Properties	80
Full-Cost Ceiling Test	80
Asset Retirement Obligation	81
Natural Gas and Oil Reserve Quantities	81
Revenue Recognition	81
Price Risk Management Activities	82
Stock Based Compensation	82
New Accounting Pronouncements Issued But Not Yet Adopted	83
Recently Adopted Accounting Pronouncements	83
Business	84
Overview	84	��
Business Strategies	86
Competitive Strengths	86
Our Relationship with Vinland	87
Description of Our Properties	89
Natural Gas Prices	90
Natural Gas and Oil Data	91
Operations	94
Management	103
Our Board of Directors	103
Compensation Committee Interlocks and Insider Participation	105
Our Board of Directors and Executive Officers	105
Compensation Discussion and Analysis	107
Compensation Objectives	107
Compensation Committee	107
Compensation Philosophy	107
Elements of Compensation	107
Executive Compensation	108
Employment Agreements	108
Grants of Plan-Based Awards	111
Long-Term Incentive Plan	111
Class B Units	114
Potential Payments upon Termination or Change-in-Control	114
Compensation of Directors	116
Employee Benefits	116
Security Ownership of Certain Beneficial Owners and Management	117
Certain Relationships and Related Party Transactions	119
Management Services Agreement	119
Participation Agreement	120
Gathering and Compression Agreement	120
Operating Agreements	121
Well Services Agreements	121
Indemnity Agreement	121
Revenue Payment Agreement	122
Registration Rights Agreement	122
Omnibus Agreement	122
Conflicts of Interest and Fiduciary Duties	124
Conflicts of Interest	124
Fiduciary Duties	126
Description of the Units	127
The Units	127
Transfer Agent and Registrar	127
Transfer of Units	127

The Limited Liability Company Agreement		128
Organization		128
Purpose		128
Fiduciary Duties		128
Agreement to be Bound by Limited Liability Company Agreement; Power of Attorney		129
Capital Contributions		129
Limited Liability		129
Voting Rights		130
Issuance of Additional Securities		130
Election of Members of Our Board of Directors		130
Removal of Members of Our Board of Directors		131
Amendment of Our Limited Liability Company Agreement		131
Merger, Sale or Other Disposition of Assets		132
Termination and Dissolution		133
Liquidation and Distribution of Proceeds		133
Anti-Takeover Provisions		133
Limited Call Right		134
Meetings; Voting		135
Non-Citizen Assignees; Redemption		135
Indemnification		136
Books and Reports		136
Right To Inspect Our Books and Records		136
Registration Rights		137
Units Eligible for Future Sale		138
Material Tax Consequences		140
Partnership Status		141
Unitholder Status		142
Tax Consequences of Unit Ownership		143
Tax Treatment of Operations		149
Disposition of Units		152
Uniformity of Units		155
Tax-Exempt Organizations and Other Investors		155
Administrative Matters		156
State, Local and Other Tax Considerations		158
Investment in our Company by Employee Benefit Plans		160
Underwriting		161
Validity of the Units		164
Experts		164
Where You Can Find More Information		164
Index to Financial Statements		F-1
APPENDIX A—Form of Second Amended and Restated Limited Liability Company Agreement of Vanguard Natural Resources, LLC		A-1
APPENDIX B—Glossary of Terms		B-1
APPENDIX C—Reserve Report		C-1

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 only. Our business, financial condition, results of operations and prospects may have changed since that date.

iii

Until , 2007 (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.

As used in this prospectus, unless we indicate otherwise: (1) “Vanguard Natural Resources, LLC,” “Vanguard,” “we,” “our,” “us” or like terms when used with respect to periods prior to completion of the separation of our operating company and Vinland, or the Nami Restructuring Plan, refer to our predecessor and, when used with respect to periods after completion of the Nami Restructuring Plan, refer to Vanguard Natural Resources, LLC and its subsidiaries, (2) “Vinland” refers to Vinland Energy Eastern, LLC, a Delaware limited liability company that is affiliated with our largest beneficial owner, and its affiliates and subsidiaries, (3) “Nami” refers to Majeed S. Nami and certain of his affiliates and related persons, which collectively own approximately 90% of Vinland and will own an approximate 29.7% membership interest in us upon completion of this offering, assuming no exercise of the underwriters’ option to purchase additional units, (4) “our operating company” or “our predecessor” refers to Vanguard Natural Gas, LLC (formerly Nami Holding Company, LLC), (5) “Citi” refers to Citigroup Global Markets Inc. and (6) references to our pro forma financial information and reserve data refer to our historical financial information and reserve data as adjusted to give effect to transactions described in the pro forma financial statements included elsewhere in this prospectus.

PROSPECTUS SUMMARY

This summary highlights information contained elsewhere in this prospectus. You should read the entire prospectus carefully, including the historical and unaudited pro forma consolidated financial statements and the notes to those financial statements. Unless otherwise indicated, the information presented in this prospectus assumes (1) an initial public offering price of $23.00 per common unit and (2) that the underwriters’ option to purchase additional common units is not exercised. You should read “Risk Factors” beginning on page 20 for information about important factors that you should consider carefully before buying our common units. We include a glossary of some of the terms used in this prospectus in Appendix B. Our natural gas and crude oil reserve information as of March 31, 2007 included in this prospectus was based on a reserve report prepared by Netherland Sewell & Associates, Inc., or NSAI, an independent engineering firm. A summary prepared by NSAI of its reserve report relating to our properties on a pro forma basis as of March 31, 2007 is provided in Appendix C and is referred to in this prospectus as the reserve report.

Vanguard Natural Resources, LLC

We are an independent natural gas and oil company focused on the acquisition, development and exploitation of mature, long-lived natural gas and oil properties. Our primary business objective is to generate stable cash flows allowing us to make quarterly cash distributions to our unitholders, and over time to increase our quarterly cash distributions. Our properties are located in the southern portion of the Appalachian Basin, primarily in southeast Kentucky and northeast Tennessee. Please read “Business—Description of Our Properties.”

We were formed in October 2006 and on April 18, 2007 but effective January 5, 2007 our predecessor was separated in the Nami Restructuring Plan into our operating subsidiary and Vinland Energy Eastern, LLC, an affiliate of Mr. Nami, who together with certain of his affiliates and related persons, is our largest unitholder. As part of the separation, we retained all of our predecessor’s proved producing wells and associated reserves. We also retained 40% of our predecessor’s working interest in the known producing horizons in approximately 95,000 gross undeveloped acres, which accounted for approximately 25% of our pro forma estimated proved reserves as of March 31, 2007, and a contract right to receive approximately 99% of the net proceeds from the sale of production from certain producing oil and gas wells, which accounted for approximately 5% of our pro forma estimated proved reserves as of March 31, 2007. In the separation, Vinland was conveyed the remaining 60% of our predecessor’s working interest in the known producing horizons in this acreage, and 100% of our predecessor’s working interest in depths above and 100 feet below our known producing horizons. Vinland acts as the operator of our existing wells and all of the wells that we drill in this area. The separation was effected to facilitate our formation, as we are a company focused on lower risk production, development and exploitation opportunities, while Vinland pursues higher capital intensive development, exploitation and exploration opportunities. Our working interest in any particular well in our drilling program will vary based on the lease or leases on which such well is located and the participation of any minority owners in the drilling of such well. For the six months ended June 30, 2007, we drilled 41 gross wells in which we own an approximate 39% working interest. For a description of our working interest in proved producing wells, please read “Business—Description of Our Properties.”

approximately 95,000 gross undeveloped acres, fall within an approximate 750,000 acre area, which we refer to in this prospectus as the “area of mutual interest,” or AMI. We have agreed with Vinland until January 5, 2012 to offer the other the right to participate in any acquisition, exploitation and development opportunities that arise in the AMI, subject however to Vinland’s right to consummate up to two acquisitions with a purchase price of $5 million or less annually without a requirement to offer us the right to participate in such acquisitions.

Our average proved reserves-to-production ratio, or average reserve life, is approximately 15 years based on our estimated proved reserves as of March 31, 2007 and our production for the twelve months ended March 31, 2007. During 2006, we drilled 100 gross wells (87 of which we retained in the Nami Restructing Plan, while the other 13 wells were located outside the AMI and not producing at the time of the separation and were thus conveyed to Vinland). We have drilled 41 gross (16 net) wells for the six months ended June 30, 2007. As reflected in the reserve report, as of March 31, 2007, we had identified 338 proved undeveloped drilling locations and over 171 other drilling locations on our leasehold acreage. Pursuant to our participation agreement with Vinland, Vinland generally has control over our drilling program and the sole right to determine which wells are drilled until January 5, 2011. During this period, we will meet with Vinland on a quarterly basis to review Vinland’s proposal to drill not less than 25 nor more than 40 gross wells, in which we will own an approximate 40% working interest, in any quarter. Up to 20% of the proposed wells may be carried over and added to the wells to be drilled in the subsequent quarter, provided that Vinland is required to drill at least 100 gross (approximately 40 net) wells per calendar year. If Vinland proposes the drilling of less than 25 gross wells in any quarter, we have the right to propose the drilling of up to a total of 14 wells, in which we will own an approximate 100% working interest, in a given quarterly period. Based on our production rate at March 31, 2007 and June 30, 2007, we believe we need to drill approximately 130 gross (52 net) wells per year to maintain our production at current levels. By contrast, based upon a sensitivity analysis prepared by NSAI, if Vinland only drills its minimum commitment of 100 gross wells per calendar year our total production is expected to decline by an average of approximately 2.7% per year for the three-year period beginning March 31, 2007. If Vinland drills its minimum commitment, we do not have the ability to drill our own additional wells in the AMI. If either party elects not to participate in the drilling of the proposed wells or future operations with respect to drilled wells, such party forfeits all right, title and interest in the natural gas and oil production that may be produced from such wells. The participation agreement will remain in place until January 5, 2012 and shall continue thereafter on a year to year basis until such time as either party elects to terminate the agreement. The obligations of the parties with respect to the drilling program described above will expire on January 5, 2011, after which we each will have the right to propose the drilling of wells within the AMI and thereby offer participation in such proposed drilling to the other party and if either party elects not to participate in such proposed drilling or future operations with respect to drilled wells, such party forfeits all right, title and interest in the natural gas and oil production that may be produced from such wells. Please read “Certain Relationships and Related Party Transactions.”

The Appalachian Basin is a mature producing region with well known geologic characteristics. Reserves in the Appalachian Basin have typically had a high degree of step-out development success; that is, as development progresses, reserves from newly completed wells are reclassified from the proved undeveloped to the proved developed category and additional adjacent locations are added to proved undeveloped reserves. As a result, the cumulative amount of total proved reserves tends to increase as development progresses. Wells that we have drilled in the Appalachian Basin generally produce little or no water, contributing to a low cost of operation. Natural gas produced in the Appalachian Basin typically sells for a premium to New York Mercantile Exchange, or NYMEX, natural gas prices due to the proximity to major consuming markets in the northeastern United States. For the year ended December 31, 2006, the average premium over NYMEX for natural gas delivered to our primary delivery points in the Appalachian Basin on the Columbia Gas Appalachian, or TECO, system was $0.23 per

MMBtu. In addition, most of our natural gas production has historically had a high Btu content, resulting in an additional premium to NYMEX natural gas prices.

We enter into hedging arrangements to reduce the impact of natural gas price volatility on our cash flow from operations. Currently, we use a combination of fixed-price TECO swaps and NYMEX put options to hedge natural gas prices. Our fixed-priced swaps in place from July 1, 2007 through 2011 hedge approximately 80% of our expected production from wells producing at March 31, 2007 at a weighted average price of $8.33 per MMBtu. However, as a result of expected production from wells that began or are expected to begin producing after March 31, 2007, our fixed-price TECO swaps hedge approximately 60% of our total production for the twelve-month period ending September 30, 2008 at $9.00 per MMBtu. The fixed-price swap transactions are settled based upon the TECO Inside FERC Index. In addition, we also have purchased NYMEX put options with a floor of $7.50 per MMBtu covering a substantial portion of our remaining total expected gas production through 2009. The put options are settled based on the NYMEX price of natural gas at Henry Hub on the last trading day of the month.

Business Strategies

Our primary business objective is to provide stable cash flows allowing us to make quarterly cash distributions to our unitholders, and over the long-term to increase the amount of our future distributions by executing the following business strategies:

· Work with Vinland to operate our producing properties and maintain our production through the development of our large existing leasehold within our area of mutual interest;

· Make accretive acquisitions of natural gas and oil properties in the known producing basins of the continental United States characterized by a high percentage of producing reserves, long-lived, stable production and step-out development opportunities;

· Maintain a conservative capital structure to ensure financial flexibility for opportunistic acquisitions; and

· Hedge to reduce the volatility in our revenues resulting from changes in natural gas and oil prices.

Competitive Strengths

We believe our competitive strengths position us to successfully execute our business strategies. Our competitive strengths are:

· Our high-quality, long-lived reserve base with predictable decline rates and an estimated reserve life of approximately 15 years;

· Our inventory of low risk, low cost development drilling locations, which provides us with multiple years of development opportunities;

· Our relationship with Vinland, which provides us with operational, technical and development capabilities in our core Appalachian Basin operating area, and may provide opportunities for acquisitions from within its existing asset base;

· Our cost of capital, which as a flow-through entity without incentive distribution rights, should provide us with a competitive advantage in pursuing acquisitions; and

· Our strong financial position, which after application of the proceeds of this offering will include an approximate $99.1 million of borrowing capacity as of September 1, 2007 (subject to $1 million reductions per month until our next borrowing base redetermination date, October 1, 2007) under our reserve-based credit facility, which should allow us to compete effectively for opportunistic acquisitions.

Our Relationship with Vinland

General. We believe that one of our principal strengths is our relationship with Vinland. Vinland’s senior management team has an average of approximately 25 years of experience operating in the Appalachian Basin and has operated our assets on behalf of our predecessor in southeast Kentucky and northeast Tennessee since 1999. Since its formation in 1999 through the acquisition of producing properties from American Resources, Vinland has grown our predecessor through the drilling and completion of over 470 gross productive wells as well as through the acquisition of various producing properties. From 2004 through December 31, 2006, our predecessor added an estimated 21.4 Bcfe of proved natural gas and oil reserves through drilling activities. Please read “Business—Our Relationship with Vinland.”

Acquisition of Assets. A principal component of our business strategy is to grow our asset base and production through the acquisition of natural gas and oil properties characterized by long-lived, stable production. Vinland’s business strategy is to develop and divest natural gas and oil properties, generally every 12 to 24 months. We believe that the complementary nature of Vinland’s and our business strategies, the proximity of our respective asset bases, Nami’s significant equity interest in us and our right to make a first offer on future sales by Vinland of properties located within our area of mutual interest will provide us with a number of acquisition opportunities from Vinland in the future. However, Vinland has no obligation or commitment to sell any such properties to us, and can be expected to act in a manner that is beneficial to its interests. Please read “Certain Relationships and Related Party Transactions—Participation Agreement.”

Under a management services agreement, Vinland advises and consults with us regarding all aspects of our production and development operations, and provides us with administrative support services as necessary for the operation of our business. Pursuant to this agreement, we pay Vinland a monthly fee equal to $60 per producing well for the services provided under the agreement. Please read “Certain Relationships and Related Party Transactions—Management Services Agreement.”

Gathering and Compression. Under a gathering and compression agreement that we entered into with Vinland, Vinland will gather, compress, deliver and provide the services necessary for us to market our natural gas production in the area of mutual interest. Vinland will deliver our natural gas production to certain designated interconnects with third-party transporters. We pay Vinland a fee of $0.25 per Mcf, plus our proportionate share of fuel and line loss for producing wells as of January 5, 2007. For all wells drilled after January 5, 2007, we pay Vinland a fee of $0.55 per Mcf, plus our proportionate share of fuel and line loss. Please read “Certain Relationships and Related Party Transactions—Gathering and Compression Agreement.”

While our relationship with Vinland is a significant strength, it is also a source of potential conflicts. For example, neither Vinland, nor any of its affiliates, is restricted from competing with us outside the area of mutual interest. Vinland or its affiliates may acquire or invest in natural gas and oil properties or other assets outside of the area of mutual interest in the future without any obligation to offer us the opportunity to purchase or own interests in those assets. For example, Vinland is currently undertaking several other natural gas and oil exploration and production projects in Appalachia within and outside of the AMI that are targeting both conventional and unconventional natural gas and oil reserves, including coalbed methane gas.

Cash Distribution Policy

Our board of directors has adopted a cash distribution policy to pay a regular quarterly distribution of $0.425 per unit on our outstanding common units and Class B units while reinvesting in our business a portion of our operating cash flow. We intend to pay our first cash distribution on or about February 14, 2007 for the period from the closing of this offering through December 31, 2007. We will adjust our first distribution based on the actual length of that period. Thereafter, we intend to pay a distribution on a quarterly basis. Declaration and payment of distributions is at the discretion of our board of directors, which distributions may be reduced or eliminated.

In general, it is our policy to distribute substantially all of our available cash after paying our operating expenses, including payments to Vinland for monthly fees based on the number of our producing wells within the AMI and reimbursement of expenses it incurs on our behalf, and retaining an amount of funds that our board of directors estimates is adequate for the proper conduct of our business, including the maintenance of our asset base. If we continue this policy, we will be dependent on our ability to raise debt and equity from the capital markets to grow our asset base, and we may not be able to access such markets. If our board of directors underestimates the amounts necessary to maintain our asset base or we fail to invest those funds effectively, our board of directors will likely need to reduce the amount of our distributions. In an effort to reduce the uncertainty regarding our distributions, our board of directors intends to increase our distributions per unit only if it believes that (i) we have sufficient reserves and liquidity for the proper conduct of our business, including the maintenance of our asset base, and (ii) we can maintain such increased distribution level for a sustained period. You may not receive distributions in the expected amounts described above, or at all. Please read “Risk Factors—Risks Related to Our Business.”

If we had completed the transactions contemplated in this prospectus on January 1, 2006, pro forma available cash generated during the year ended December 31, 2006 and the twelve months ended June 30, 2007 would have been approximately $11.9 million and $12.6 million, respectively. This amount of pro forma cash available for distribution would have been sufficient to allow us to pay approximately 64% and 68%, respectively, of the initial quarterly distributions on our common units and Class B units during these periods (59% and 63%, respectively, assuming the underwriters exercise in full their option to purchase additional common units). For a calculation of our ability to make distributions to you based on our pro forma results for the year ended December 31, 2006 and the twelve months ended June 30, 2007, please read “Cash Distribution Policy and Restrictions on Distributions” included elsewhere in this prospectus.

Pursuant to the terms of our limited liability company agreement, our board of directors has the discretionary authority to cause us to borrow funds from our reserve-based credit facility to make up a shortfall in cash available for distribution such as the estimated shortfall amounts discussed above. Under our reserve-based credit facility, we will be able to incur debt to pursue our business plan and to pay distributions to our unitholders, provided that our borrowings do not reach or exceed 50% of the borrowing base and that we are not then in default. For a description of our borrowing parameters and covenants, please read “Cash Distribution Policy and Restrictions on Distributions.”

Summary of Risk Factors

An investment in our units involves risks associated with our business, regulatory and legal matters, our limited liability company structure and the tax characteristics of our units. The following list of risk factors is not exhaustive. Please read carefully the risks under the caption “Risk Factors.”

Risks Related to Our Business

· We may not have sufficient cash from operations to pay the initial quarterly distribution on our common units following establishment of cash reserves and payment of fees and expenses.

· We intend to rely on Vinland, an affiliate of our largest beneficial owner, to execute our drilling program. If Vinland 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 to our unitholders.

· We could lose our interests in future wells if we fail to participate under our participation and operating agreements with Vinland in the drilling of these wells.

· We are exposed to the credit risk of Vinland and any material nonperformance by Vinland could reduce our ability to make distributions to our unitholders.

· Our estimated reserves are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

Risks Related to Our Structure

· Mr. Nami, who together certain of his affiliates and related persons, will own approximately 29.7% of our outstanding common units after this offering, and certain members of our board of directors who are officers or directors of Vinland Energy Eastern may have conflicts of interest with us. The ultimate resolution of these conflicts of interest may result in favoring the interests of these other parties over yours and may be to our detriment. Our limited liability company agreement limits the remedies available to you in the event you have a claim relating to conflicts of interest.

· You will experience immediate and substantial dilution of $14.45 per common unit.

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

Tax Risks to Unitholders

· 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 IRS were to treat us as a corporation for federal income tax purposes or we were to become subject to entity-level taxation for state tax purposes, taxes paid, if any, would reduce the amount of cash available for distribution to you.

· You may be required to pay taxes on income from us even if you do not receive any cash distributions from us.

· If the IRS contests the federal income tax positions we take, the market for our units may be adversely impacted and the costs of any IRS contest will reduce our cash available for distribution.

· Tax-exempt entities and foreign persons face unique tax issues from owning units that may result in adverse tax consequences to them.

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

· We prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular common 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.

· 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.

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

Private Placement

In April 2007, we completed a private equity offering pursuant to which we issued 2,290,000 units to certain private investors, including an affiliate of Lehman Brothers Inc., which we collectively refer to as the Private Investors, for $41.2 million. We used the proceeds of this private equity offering to make a $41.2 million distribution to Nami, who used a portion of these funds to capitalize Vinland and also pay us $3.9 million to reduce outstanding accounts receivable from Vinland. We then used the $3.9 million to repay borrowings and interest under our reserve-based credit facility and for general limited liability company purposes.

Reserve-Based Credit Facility

On January 3, 2007, our operating company entered into a reserve-based credit facility. Our initial borrowing base under the reserve-based credit facility was set at $115.5 million, of which $109.0 million was outstanding as of June 30, 2007. As of September 1, 2007, our borrowing base was $112.5 million, of which $107.8 million was outstanding as of September 1, 2007. The borrowing base of our reserve-based credit facility is subject to $1 million reductions per month until our next borrowing base redetermination date of October 1, 2007. The reserve-based credit facility is available for our general limited liability company purposes, including, without limitation, capital expenditures and acquisitions. Our obligations under the reserve-based credit facility are secured by substantially all of our assets. We intend to use a portion of the net proceeds from this offering to repay approximately 88% of the $107.8 million of indebtedness outstanding as of September 1, 2007 under the reserve-based credit facility. We will use the net proceeds, if any, from the exercise of the underwriters’ option to further reduce our outstanding borrowings under our reserve-based credit facility.

Our LLC Structure

We are a Delaware limited liability company that was formed in October 2006. We are a holding company, and our operating assets will be owned directly or indirectly by our operating subsidiary, Vanguard Natural Gas, LLC, which was contributed to us on April 18, 2007 in connection with our private

equity offering described above. At the closing of this offering and the application of the related net proceeds:

· our management will own 420,000 Class B units, representing an aggregate 3.8% membership interest in us;

· Nami and certain of his affiliates and related persons will own 3,250,000 common units, representing an aggregate 29.7% membership interest in us;

· the Private Investors will own 2,290,000 common units, representing an aggregate 20.9% membership interest in us; and

· the public unitholders will own 5,000,000 common units, representing an aggregate 45.6% membership interest in us.

We issued 240,000 Class B units and 125,000 Class B units to Scott W. Smith, our President and Chief Executive Officer, and Richard A. Robert, our Executive Vice President and Chief Financial Officer, respectively. In August 2007, we issued 50,000 Class B units to Britt Pence, our Vice President of Engineering and 5,000 Class B units to Patty Avila-Eady, our Financial Reporting Manager. There are an additional 40,000 Class B units available to be issued in the future. The Class B units have substantially the same rights as the common units and, upon vesting, will become convertible at the election of the holder into common units. Unless the context otherwise requires, all references to our “common units” or our “units” refer collectively to our common units and our Class B units, each representing membership interest in us.

Our board of directors has sole responsibility for overseeing our business. Because we do not have any field operations, we substantially rely on Vinland to operate our natural gas and oil properties. We currently have four full-time employees, each of whom is located in our Houston office. Our principal executive offices are located at 7700 San Felipe, Suite 485, Houston, Texas 77063, and our telephone number is (832) 327-2255. Upon closing of this offering, our website will be located at www.vnrllc.com.

The diagram on the following page depicts our organizational structure after our initial public offering.

Organizational Structure

(1) If the underwriters’ option to purchase additional common units is exercised in full, Nami’s percentage ownership of common units will be reduced to 27.8% of all then outstanding units, the Private Investors’ percentage ownership of common units will be reduced to 19.6% of all then outstanding units, management’s membership interest will be reduced to 3.6%, and the ownership interest of the public unitholders will increase to 5,750,000 common units, or 49.1% of all the outstanding units.

(2) 240,000 Class B units have been issued to Scott W. Smith, our President and Chief Executive Officer, 125,000 Class B units have been issued to Richard A. Robert, our Executive Vice President and Chief Financial Officer, 50,000 Class B units have been issued to Britt Pence, our Vice President of Engineering and 5,000 Class B units have been issued to Patty Avila-Eady, our Financial Reporting Manager. There are an additional 40,000 Class B units available to be issued in the future.

(3) As of June 30, 2007, we owned an approximate 90% working interest in 891 wells in Tennessee and Kentucky and Vinland owned an approximate 60% working interest in 41 of the wells in Kentucky. We and Vinland also own approximately 40% and 60%, respectively, of our predecessor’s working interests in the known producing horizons in approximately 95,000 gross acres in Tennessee and Kentucky.

The Offering

Units offered by us		5,000,000 common units.
		5,750,000 common units if the underwriters exercise their option to purchase 750,000 additional common units in full.
Units outstanding after this offering		10,540,000 common units and 420,000 Class B units; 11,290,000 common units and 420,000 Class B units if the underwriters’ exercise their option to purchase additional units in full.
Use of proceeds		We anticipate using the estimated net proceeds of approximately $107.0 million(1) from this offering, after deducting the estimated underwriting discounts and fees of approximately $8.0 million, to:
		· repay $94.4 million of the indebtedness outstanding under our reserve-based credit facility;
		· pay $4.3 million of accrued and unpaid distributions to Nami, management and the Private Investors under our limited liability company agreement;
		· pay $1.0 million of remaining expenses associated with this offering; and
		· pay $7.3 million in deferred swap payments to our swap counterparties related to resetting our 2007, 2008 and 2009 natural gas swap contracts at higher prices in May 2007. Please read “Use of Proceeds.”
		(1) Assumes an initial public offering price of $23.00 per common unit, the mid-point of the price range set forth on the cover page of this prospectus and after deducting estimated underwriting discounts and commissions of $7.6 million and structuring fees of $0.4 million.
		We will use the net proceeds, if any, from the exercise of the underwriters’ option to further reduce our outstanding borrowings under our reserve-based credit facility.
Cash distributions		We will distribute all of our cash on hand at the end of each quarter, after payment of fees and expenses, including payments to Vinland for monthly fees based on the number of our producing wells within the AMI and reimbursement of expenses it incurs on our behalf, less reserves established by our board of directors. We refer to this cash as “available cash,” and we define its meaning in more detail in our limited liability company agreement and in the glossary found in Appendix B. Our board of directors has broad discretion in establishing reserves for the proper conduct of our business. These reserves, which could be substantial, will reduce the amount of cash available for distribution to you.

		We intend to make an initial quarterly distribution of $0.425 per unit to the extent we have sufficient available cash. The amount of available cash, if any, at the end of any quarter may be greater than or less than the aggregate initial quarterly distribution to be distributed on all units.
		Our board of directors has adopted a policy that it will raise our quarterly cash distribution only when it believes that we (i) have sufficient reserves and liquidity for the proper conduct of our business, including the maintenance of our asset base, and (ii) can maintain such increased distribution level for a sustained period. While this is our current policy, our board of directors may alter such policy in the future when and if it determines such alteration to be appropriate. Our limited liability company agreement requires that, within 45 days after the end of each calendar quarter beginning with the quarter ending December 31, 2007, we distribute all of our available cash to holders of record of our limited liability company interests on the applicable record date.
		We will adjust the initial quarterly distribution for the period from the closing of this offering through December 31, 2007, based on the actual length of the period.
		Based on the assumptions and considerations included in “Cash Distribution Policy and Restrictions on Distributions—Assumptions and Considerations” of this prospectus, we expect to have sufficient cash generated from operations, to fund our drilling program and to pay the initial quarterly distribution of $0.425 on all units for each quarter through September 30, 2008. If we had completed the transactions contemplated in this prospectus on January 1, 2006, pro forma available cash generated during the year ended December 31, 2006 and the twelve months ended June 30, 2007 would have been approximately $11.9 million and $12.6 million, respectively. This amount of pro forma cash available for distribution would have been sufficient to allow us to pay approximately 64% and 68%, respectively, of the initial quarterly distributions on our units during these periods (59% and 63%, respectively, assuming the underwriters exercise in full their option to purchase additional common units). For a calculation of our ability to make distributions to you based on our pro forma results for the twelve months ended September 30, 2008, please read “Cash Distribution Policy and Restrictions on Distributions.”
Issuance of additional units		We can issue an unlimited number of additional limited liability company interests without the consent of our unitholders. Please read “Risk Factors—Risks Related to Our Structure—We may issue additional units without your approval, which would dilute your existing ownership interests,” “Units Eligible for Future Sale” and “The Limited Liability Company Agreement—Issuance of Additional Securities.”

Agreement to be bound by Limited Liability Company Agreement; Voting rights		By purchasing a common unit in us, you will be admitted as a unitholder of our company and will be deemed to have agreed to be bound by all of the terms of our limited liability company agreement. Pursuant to our limited liability company agreement, as a unitholder you will be entitled to vote on the following matters:
		· the annual election of members of our board of directors;
		· specified amendments to our limited liability company agreement;
		· the merger of our company or the sale of all or substantially all of our assets; and
		· the dissolution of our company.
		Please read “The Limited Liability Company Agreement—Voting Rights.”
Board of Directors		Our current board of directors consists of three members. Prior to the completion of this offering, one of our existing directors will resign and our board of directors will appoint one independent member to our board of directors. Our current board of directors is expected to appoint one additional independent member of our board of directors within 90 days of the pricing of this offering and one additional independent member of our board of directors within one year of the pricing of this offering. The current members and the remaining members of the board expected to be appointed following the pricing of this offering will serve until the first annual meeting of the holders of our units following this offering and will be subject to re-election annually. The removal of a director elected by our unitholders requires the approval of the holders of not less than 662¤3% of our outstanding units, and as such, our public unitholders will not be able to remove a member of our board of directors unless either Nami or the Private Investors vote their units in favor of such a removal.
Limitations on unitholder actions		Our limited liability company agreement (i) prohibits unitholders from taking unitholder action by written consent and (ii) nullifies the unitholder voting rights of any person other than Nami or its affiliates that holds 20% or more of our outstanding units.
Limited call right		If at any time any person and its affiliates own more than 90% of the outstanding units, such person will have the right, but not the obligation, to purchase all of the remaining units at a price not less than the then-current market price of the units.

Fiduciary duties		Our limited liability company agreement provides that except as expressly modified by its terms, the fiduciary duties of our directors and officers are identical to the fiduciary duties they would have as directors and officers of a Delaware corporation.
		Our limited liability company agreement establishes a conflicts committee of our board of directors, consisting solely of independent directors, which will be responsible for reviewing transactions involving potential conflicts of interest. If the conflicts committee approves such a transaction, you will not be able to assert that such approval constituted a breach of fiduciary duties owed to you by our directors and officers. Please read “Management—Our Board of Directors.”
Estimated ratio of taxable income to distributions		We estimate that if you hold the common units that 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 less than 30% of the cash distributed to you with respect to that period. Please read “Material Tax Consequences—Tax Consequences of Unit Ownership” for the basis of this estimate.
Listing and trading symbol		Our common units have been approved for listing, subject to official notice of issuance, on the NYSE Arca under the symbol “VNR.”

Summary Historical and Pro Forma Consolidated Financial And Operating Data

Set forth below is summary historical and pro forma consolidated financial and operating data for the periods indicated for Vanguard Natural Resources, LLC and Vanguard Natural Gas, LLC, our predecessor. The summary historical financial data for the years ended December 31, 2004, 2005 and 2006 and the balance sheet data as of December 31, 2004, 2005 and 2006 have been derived from the audited financial statements of our predecessor. The summary historical financial data for the six months ended June 30, 2006 and 2007 and the balance sheet data as of June 30, 2006 and 2007 have been derived from the unaudited financial statements of Vanguard Natural Resources, LLC or its predecessor. The pro forma as adjusted statement of operations data for the year ended December 31, 2006 gives effect to the following transactions as if such transactions occurred on January 1, 2006:

· the separation of our predecessor and Vinland as part of the Nami Restructuring Plan;

· the contribution of our predecessor to Vanguard Natural Resources, LLC

· our recent private placement;

· the granting of 420,000 Class B units to management and the granting of 40,000 common units to future employees and/or board members following the completion of this offering; and

· this offering.

Because the transactions referred to in the first three bullet points above occurred during the interim period, their impact is included in our unaudited pro forma consolidated statement of operations for the six months ended June 30, 2007 and the unaudited pro forma consolidated balance sheet at June 30, 2007 as adjusted financial statements. Accordingly, the pro forma as adjusted statement of operations data for the six months ended June 30, 2007 and the pro forma as adjusted balance sheet as of June 30, 2007 gives effect to the following transactions as if such transactions occurred on January 1, 2007 and June 30, 2007, respectively:

· the granting of 420,000 Class B units to management and the granting of 40,000 common units to future employees and/or board members following the completion of this offering; and

· this offering.

You should read the following summary financial data in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our financial statements and related notes appearing elsewhere in this prospectus. You should also read the pro forma information together with the Unaudited Pro Forma Financial Statements and related notes included in this prospectus.

The following table presents a non-GAAP financial measure, adjusted EBITDA, which we use in our business. This measure is not calculated or presented in accordance with generally accepted accounting principles, or GAAP. We explain this measure below and reconcile it to the most directly comparable financial measure calculated and presented in accordance with GAAP in “—Non-GAAP Financial Measure.”

	Predecessor													Vanguard				Pro Forma As Adjusted
	Year Ended December 31,									Six Months Ended June 30,				Six Months Ended June 30,				Year Ended December 31,				Six Months Ended June 30,
	2004			2005			2006			2006				2007				2006				2007
										(unaudited)				(unaudited)				(unaudited)				(unaudited)
										(in thousands)
Statement of Operations Data:
Revenues:
Natural gas and oil sales	$	23,881		$	40,299		$	38,184			$	19,416			$	19,068			$	38,185			$	19,068
Realized losses on derivative contracts	(5,926		)	(10,024		)	(2,208		)		(2,341		)		(1,666		)		(2,208		)		(1,666		)
Change in fair value of derivative contracts(1)	(991		)	(18,779		)	17,748				11,424				—				17,748				—
Other	29			451			665				—				—				—				—
Total revenues	16,993			11,947			54,389				28,499				17,402				53,725				17,402
Costs and Expenses:
Lease operating expenses	2,407			4,607			4,896				2,375				2,460				5,068				2,460
Depreciation, depletion and amortization	4,029			6,189			8,633				4,047				4,320				7,927				4.320
Selling, general and administrative	3,154			5,946			5,199				960				1,215				8,876				3,584
Bad debt expense	—			—			—								1,008				—				1,008
Taxes other than income	611			1,249			1,774				651				891				1,731				891
Total costs and expenses	10,201			17,991			20,502				8,033				9,894				23,602				12,263
Income (Loss) from Operations:	6,792			(6,044		)	33,887				20,466				7,508				30,123				5,139
Other Income and (Expenses):
Interest income	7			52			40				18				28				40				28
Interest and financing expenses	(1,455		)	(4,566		)	(7,372		)		(3,784		)		(4,420		)		—				(695		)
Loss on extinguishment of debt	—			—			—				—				(2,502		)		—				(2,502		)
Total other income and (expenses)	(1,448		)	(4,514		)	(7,332		)		(3,766		)		(6,894		)		40				(3,169		)
Net income (loss)	$	5,344		$	(10,558	)	$	26,555			$	16,700			$	614			$	30,163			$	1,970
Cash Flow Data:
Net cash provided by/(used in) operating activities(1)	$	9,607		$	10,530		$	16,087			$	7,229			$	(2,833	)		$	—			$	—
Net cash used in investing activities	(19,598		)	(37,068		)	(37,383		)		(14,326		)		(6,620		)		—				—
Net cash provided by financing activities	12,721			25,571			19,985				5,196				12,167				—				—
Other Financial Information (unaudited):
Adjusted EBITDA(2)	$	11,812		$	18,924		$	24,772			$	13,089			$	13,167			$	24,315			$	12,243

	Predecessor									Vanguard				Pro Forma As Adjusted
	As of December 31,						As of June 30,			As of June 30,				As of December 31			As of June 30,
	2004		2005		2006		2006			2007				2006			2007
							(unaudited)			(unaudited)				(unaudited)			(unaudited)
							(in thousands)
Balance Sheet Data:
Cash and cash equivalents	$	4,009	$	3,041	$	1,731		$	1,141		$	4,445			$	888		$	4,445
Other current assets	10,033		19,598		20,438			22,075			9,130				7,095			7,558
Natural gas and oil properties, net of accumulated depreciation, depletion and amortization	54,761		83,513		104,684			89,789			101,611				95,350			101,611
Property, plant and equipment, net of accumulated depreciation	1,894		4,104		11,873			8,206			31				—			31
Other assets	—		—		—			—			4,785				5,255			4,785
Total assets	$	70,697	$	110,256	$	138,726		$	121,211		$	120,002			$	108,588		$	118,430
Short-term derivative liabilities	$	800	$	11,527	$	2,022		5,395			—				$	2,022		—
Other current liabilities	6,347		12,033		11,505			13,532			12,581				8,528			5,258
Long-term debt	42,318		72,708		94,068			78,707			109,000				—			14,623
Long-term derivative liabilities	191		8,243		—			2,951			4,049				—			4,049
Other long-term liabilities	130		212		418			313			435				418			435
Members’ capital/(deficit)	20,911		5,533		30,713			20,313			(6,063		)		97,620			94,065
Total liabilities and members’ capital	$	70,697	$	110,256	$	138,726		$	121,211		$	120,002			$	108,588		$	118,430

(1) Natural gas derivative contracts were used to reduce our exposure to changes in natural gas prices. They were not specifically designated as hedges under Statement of Financial Accounting Standards (SFAS) No. 133. Change in the fair value of these natural gas derivative contracts are marked to market in our earnings each period. Further, these amounts represent non-cash charges.

(2) See “—Non-GAAP Financial Measure.”

Summary Reserve and Operating Data

The following tables show our pro forma estimated net proved reserves as of March 31, 2007. The historical data is based on reserve reports prepared by our independent petroleum engineers, NSAI, and certain summary unaudited information with respect to our production and sales of natural gas and oil. The pro forma data gives effect to the separation of our operating company and Vinland in the Nami Restructuring Plan. A summary prepared by NSAI of its reserve report relating to our properties on a pro forma basis at March 31, 2007 is provided in Appendix C and is referred to in this prospectus as the reserve report. You should refer to “Risk Factors,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Business—Natural Gas and Oil Data—Proved Reserves” and “—Production and Price History” and the reserve report included in this prospectus in evaluating the material presented below.

	Pro Forma As of March 31, 2007
Reserve Data:
Estimated net proved reserves:
Natural gas (Bcf)		65.2
Crude oil (Mbls)		256
Total (Bcfe)		66.7
Proved developed (Bcfe)		49.8
Proved undeveloped (Bcfe)		16.9
Proved developed reserves as % of total proved reserves		75		%
Standardized Measure (in millions)(1)		$179.8
Representative Natural Gas and Oil Prices:
Natural gas—NYMEX Henry Hub per MMBtu		$	7.73
Oil—NYMEX WTI per Bbl		$	55.74

	Predecessor			Vanguard				Pro Forma
	Year Ended December 31, 2006			Six Months Ended June 30, 2007				Twelve Months Ended December 31, 2006				Six Months Ended June 30, 2007
Net Production:
Total realized production (MMcfe)		4,378			2,158				4,378				2,158
Average daily production (Mcfe/d)		11,995			11,925				11,995				11,925
Average Realized Sales Prices ($ per Mcfe):
Average realized sales prices (including hedges)		$	8.22		$	8.06			$	8.22			$	8.06
Average realized sales prices (excluding hedges)		$	8.72		$	8.83			$	8.72			$	8.83
Average Unit Costs ($ per Mcfe):
Production costs(2)		$	1.52		$	1.55			$	1.55			$	1.55
Selling, general and administrative expenses		$	1.19		$	0.56	(3)		$	2.03	(3)		$	1.66	(3)
Depreciation, depletion and amortization		$	1.97		$	2.00			$	1.81			$	2.00

(1) Standardized Measure is the present value of estimated future net revenues to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the Securities and Exchange Commission (using prices and costs in effect as of the date of estimation) without giving effect to non-property related expenses such as selling, general and administrative expenses, debt service and future income tax expenses or to depreciation, depletion and amortization and discounted using an annual discount rate of 10%. Our Standardized Measure does not include future income tax expenses because our reserves are owned by our subsidiary Vanguard Natural Gas, LLC which is not subject to income taxes. Standardized Measure does not give effect to derivative transactions. For a description of our derivative transactions, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Cash Flow from Operations.”

(2) Production costs include such items as lease operating expenses, production taxes (severance and ad valorem taxes) as well as gathering and compression fees and other customary charges. With respect to pro forma production costs, such amounts include overhead and administrative costs paid to Vinland pursuant to our management services agreement.

(3) Selling, general and administrative expenses for the historical six months ended June 30, 2007 includes $0.6 million non-cash compensation expense related to the 365,000 Class B unit grant to Messrs. Smith and Robert. This non-cash compensation expense increased selling, general and administrative expense by $0.26 per Mcfe for the six months ended June 30, 2007. Selling, general and administrative expenses for the pro forma year ended December 31, 2006 and the pro forma six months ended June 30, 2007 includes a $4.0 million and $2.0 million, respectively, non-cash compensation expense related to the 420,000 Class B unit grant to management and the granting of 40,000 common units to future employees and/or board members following the completion of this offering. This non-cash compensation expense increased selling, general and administrative expense by $0.92 per Mcfe and $0.93 per Mcfe for the pro forma year ended December 31, 2006 and the pro forma six months ended June 30, 2007, respectively.

Non-GAAP Financial Measure

Adjusted EBITDA

We define Adjusted EBITDA as net income (loss) plus:

· Net interest expense and loss on extinguishment of debt;

· Depreciation, depletion and amortization;

· Change in fair value of derivative contracts;

· Non-cash compensation expense; and

· Swap termination fees.

Adjusted EBITDA is a significant performance metric used by our management to indicate (prior to the establishment of any cash reserves by our board of directors) the cash distributions we expect to pay our unitholders. Specifically, this financial measure indicates to investors whether or not we are generating cash flow at a level that can sustain or support an increase in our quarterly distribution rates. Adjusted EBITDA is also a quantitative standard used throughout the investment community with respect to publicly-traded partnerships and limited liability companies.

Our Adjusted EBITDA should not be considered as an alternative to net income, operating income, cash flow from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Our Adjusted EBITDA excludes some, but not all, items that affect net income and operating income and these measures may vary among other companies. Therefore, our Adjusted EBITDA may not be comparable to similarly titled measures of other companies.

The following table presents a reconciliation of our consolidated net income (loss) to adjusted EBITDA (in thousands):

																						Pro Forma As Adjusted
	Year Ended December 31,														Six Months Ended June 30,							Year Ended December 31,				Six Months Ended June 30,
	2002			2003			2004		2005			2006			2006				2007			2006				2007
	(unaudited)			(unaudited)											(unaudited)				(unaudited)			(unaudited)				(unaudited)
Net income (loss)		$	2,768		$	5,395	$	5,344	$	(10,558	)	$	26,555			$	16,700			$	614		$	30,163			$	1,970
Plus:
Interest expense and loss on extinguishment of debt		1,506			1,413		1,455		4,566			7,372				3,784				6,921			—				3,197
Depreciation, depletion and amortization		2,505			3,109		4,029		6,189			8,633				4,047				4,320			7,927				4,320
Change in fair value of derivative contracts(1)		—			—		991		18,779			(17,748		)		(11,424		)		—			(17,748		)		—
Non-cash compensation expense		—			—		—		—			—				—				563			4,013				2,007
Swap termination fees		—			—		—		—			—				—				777			—				777
Less:
Interest income		6			14		7		52			40				18				28			40				28
Adjusted EBITDA		$	6,773		$	9,903	$	11,812	$	18,924		$	24,772			$	13,089			$	13,167		$	24,315			$	12,243

RISK FACTORS

Membership interests in a limited liability company 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 a similar business. 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.

The following risks could materially and adversely affect our business, financial condition or results of operations. If any of the events described below were to occur, we may not be able to pay the quarterly distributions on our common units, the trading price of our common units could decline and you could lose part or all of your investment in our company.

Risks Related to Our Business

We may not have sufficient cash from operations to pay the initial quarterly distribution on our common units following establishment of cash reserves and payment of fees and expenses.

We may not have sufficient cash flow from operations each quarter to pay the initial quarterly distribution. For example, if we had completed the transactions contemplated in this prospectus on January 1, 2006, pro forma available cash generated during the year ended December 31, 2006 and the twelve months ended June 30, 2007 would have been approximately $11.9 million and $12.6 million, respectively. These amounts of pro forma cash available for distribution would have been sufficient to allow us to pay approximately 64% and 68% of the initial quarterly distributions on our units during the respective periods (59% and 63%, respectively, assuming the underwriters exercise in full their option to purchase additional common units). Under the terms of our limited liability company agreement, the amount of cash otherwise available for distribution will be reduced by our operating expenses and the amount of any cash reserve amounts that our board of directors establishes to provide for future operations, future capital expenditures, future debt service requirements and future cash distributions to our unitholders. 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 natural gas and oil we produce;

· the price at which we are able to sell our natural gas and oil production;

· the level of our operating costs;

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

· the level of our capital expenditures.

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 our capital expenditures;

· our ability to make working capital borrowings under our reserve-based credit facility to pay distributions;

· the cost of acquisitions, if any;

· our debt service requirements;

· fluctuations in our working capital needs;

· timing and collectibility of receivables;

· restrictions on distributions contained in our reserve-based credit facility;

· prevailing economic conditions; and

· the amount of cash reserves established by our board of directors for the proper conduct of our business.

As a result of these factors, the amount of cash we distribute in any quarter to our unitholders may fluctuate significantly from quarter to quarter and may be significantly less than the initial quarterly distribution amount that we expect to distribute.

We intend to rely on Vinland, an affiliate of our largest beneficial owner, to execute our drilling program. If Vinland 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 to our unitholders.

On April 18, 2007 but effective as of January 5, 2007, we entered into various agreements with Vinland, an affiliate of our largest beneficial owner, under which we will rely on Vinland to operate all of our existing producing wells and coordinate our development drilling program. For example, pursuant to our participation agreement with Vinland, Vinland generally has control over our drilling program and the sole right to determine which wells are drilled until January 5, 2011. Under the agreements, Vinland will also advise and consult with us regarding all aspects of our production and development operations and provide us with administrative support services as necessary or useful for the operation of our business. If Vinland 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 cash distributions to you.

In addition, Vinland is not obligated to operate any properties we may acquire outside of our area of mutual interest. As a result, expanding our operations outside of our area of mutual interest may require us to develop our own operating expertise or contract with a third-party to operate our properties, either of which may increase our costs of operations, may eliminate any advantages or efficiencies we may have while Vinland operates our properties or otherwise prove unsuccessful.

Natural gas and oil prices are volatile, and if commodity prices decline significantly for a temporary or prolonged period, our cash flow from operations may 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 and demand for natural gas and oil. The natural gas and oil markets are very volatile and a drop in prices can significantly affect our financial results and impede our growth. Changes in natural gas and oil prices have a significant impact on the value of our reserves and on our cash flow. In particular, declines in commodity prices will reduce the value of our reserves, our cash flow, our ability to borrow money or raise capital and our ability to pay distributions. Prices for natural gas and oil may fluctuate widely in response to relatively minor changes in the supply of and demand for natural gas and oil, market uncertainty and a variety of additional factors that are beyond our control, such as:

· the domestic and foreign supply of and demand for natural gas and oil;

· the price and level of foreign imports;

· the level of consumer product demand;

· weather conditions;

· overall domestic and global economic conditions;

· political and economic conditions in natural gas and oil producing countries, including those in the Middle East, Africa and South America;

· the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;

· the impact of the U.S. dollar exchange rates on natural gas and oil prices;

· technological advances affecting energy consumption;

· domestic and foreign governmental regulations and taxation;

· the impact of energy conservation efforts;

· the proximity and capacity of natural gas and oil pipelines and other transportation facilities; and

· the price and availability of alternative fuels.

There is no assurance that it will effectively negate the impact of price fluctuations on all of our production. In the past, the price of natural gas has been extremely volatile, and we expect this volatility to continue. For example, during the year ended December 31, 2006 and the first eight months of 2007, the closing price of a calendar month NYMEX natural gas price ranged from a high of $11.43 per MMBtu and $7.59 per MMBtu, respectively, to a low of $4.20 per MMBtu and $5.83 per MMBtu, respectively. Our estimated cash available to pay distributions as set forth in “Cash Distribution Policy and Restrictions on Distributions” assumes that our weighted average net realized natural gas sales price for our unhedged production volumes (including our production volumes subject to put options at $7.50 per MMBtu) is $8.00 per MMBtu. If the average realized natural gas sales price for our net production volumes were to decrease by $1.00 per MMBtu, we estimate that our estimated cash available to pay distributions for the twelve months ended September 30, 2008 would decrease by approximately $0.7 million. If we raise our cash distribution level in response to increased cash flow during periods of relatively high commodity prices, we may not be able to sustain those distribution levels during periods of sustained lower commodity prices.

Unless we replace our reserves, our existing reserves and production will decline, which would adversely affect our cash flow from operations and our ability to make distributions to our unitholders.

Producing natural gas and oil wells extract hydrocarbons from underground structures referred to as reservoirs. Reservoirs contain a finite volume of hydrocarbon reserves referred to as reserves in place. Based on prevailing prices and production technologies, only a fraction of reserves in place can be recovered from a given reservoir. The volume of the reserves in place that is recoverable from a particular reservoir is reduced as production from that well continues. The reduction is referred to as depletion. Ultimately, the economically recoverable reserves from a particular well will deplete entirely and the producing well will cease to produce and will be plugged and abandoned. As a result, unless we are able over the long-term to replace the reserves that are produced, investors in our units should consider the cash distributions that are paid on the units not merely as a “yield” on the units, but as a combination of both a return of capital and a return on investment. Investors in our units will have to obtain the return of capital invested out of cash flow derived from their investments in units during the period when reserves can be economically recovered. Accordingly, we give no assurances that the distributions you receive over the life of your investment will meet or exceed your initial capital investment.

Producing natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Based on our March 31, 2007 reserve report, our average annual decline rate for our pro forma proved developed producing reserves is approximately 11% during the first five years, 6% in the next five years and less than 5% thereafter. This rate of decline will change if production from our existing wells declines in a different manner than we have estimated and can change when we drill additional wells, make acquisitions and under other circumstances. Thus, our future natural gas reserves and production and, therefore, our cash flow and income are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or

acquiring additional recoverable reserves. Based on our production rate at March 31, 2007 and June 30, 2007, we believe we need to drill approximately 130 gross (52 net) wells per year to maintain our production at current levels. As reflected in the reserve report, as of March 31, 2007, we had identified 338 proved undeveloped drilling locations and over 171 other drilling locations on our leasehold acreage. As a result, assuming we drill approximately 130 of our identified drilling locations per year, we believe that our current inventory of identified drilling locations will only be sufficient to maintain our current total production for approximately four years from March 31, 2007, the date of the reserve report.

Vinland controls our drilling program. Vinland has agreed to drill not less than 100 gross wells per calendar year through January 5, 2011. If Vinland drills only its minimum commitment, our total production is expected to decline by an average of approximately 2.7% per year for the three-year period beginning March 31, 2007.

Pursuant to our participation agreement with Vinland, Vinland generally has control over our drilling program and the sole right to determine which wells are drilled until January 5, 2011. During this period, we will meet with Vinland on a quarterly basis to review Vinland’s proposal to drill not less than 25 nor more than 40 gross wells, in which we will own an approximate 40% working interest, in any quarter. Up to 20% of the proposed wells may be carried over and added to the wells to be drilled in the subsequent quarter, provided that Vinland is required to drill at least 100 gross (approximately 40 net) wells per calendar year. If Vinland proposes the drilling of less than 25 gross wells in any quarter, we have the right to propose the drilling of up to a total of 14 wells, in which we will own an approximate 100% working interest, in a given quarterly period. Based on our production rate at March 31, 2007 and June 30, 2007, we believe we need to drill approximately 130 gross (52 net) wells per year to maintain our production at current levels. Based upon a sensitivity analysis prepared by NSAI, if Vinland only drills its minimum commitment of 100 gross wells per calendar year, our total production is expected to decline by an average of approximately 2.7% per year for the three-year period beginning March 31, 2007. If Vinland drills its minimum commitment, we do not have the ability to drill our own additional wells in the AMI. If either party elects not to participate in the drilling of the proposed wells or future operations with respect to drilled wells, such party forfeits all right, title and interest in the natural gas and oil production that may be produced from such wells. The participation agreement will remain in place until January 5, 2012 and shall continue thereafter on a year to year basis until such time as either party elects to terminate the agreement. The obligations of the parties with respect to the drilling program described above will expire on January 5, 2011. Please read “Certain Relationships and Related Party Transactions.”

We could lose our interests in future wells if we fail to participate under our participation and operating agreements with Vinland in the drilling of these wells.

Under the terms of our participation and operating agreements with Vinland, we may elect to forego participation in the future drilling of wells through the payment to Vinland of our share of costs related to that drilling. We may elect to forego participation in drilling wells in the future if, among other things, we do not have sufficient cash flow, the drilling prospects are not attractive to us, the commodity price environment is not favorable or there are other investment opportunities that are more attractive to us. Should we do so, we will become obligated to transfer without compensation all of our right, title and interest in those wells.

We are exposed to the credit risk of Vinland and any material nonperformance by Vinland could reduce our ability to make distributions to our unitholders.

On April 18, 2007 but effective January 5, 2007, we entered into several agreements with Vinland pursuant to which Vinland will operate all of our existing producing wells and coordinate our development drilling program. In addition, Vinland generally has control over our drilling program and the sole right to determine which wells are drilled until January 5, 2011. Vinland intends to initially fund the obligations with a portion of the proceeds of our April 2007 private placement, which we distributed to Nami, but Vinland has no obligation to use the proceeds for our drilling program and Nami has no obligation to fund

Vinland’s capital requirements with all or any portion of these proceeds or other funds. In addition, in the event Vinland becomes insolvent or is declared bankrupt, we would have to become the operator of our wells and pursue our own drilling program, which would require additional employees and increased expenses. In addition, there are no restrictions on Nami from selling his ownership in Vinland to a third party that may not perform under our agreements with Vinland. Any material nonperformance under our agreements with Vinland could materially and adversely impact our ability to operate and make distributions to our unitholders.

The amount of cash that we have available for distribution to our unitholders depends primarily upon our cash flow and not our profitability. As a result, we may be unable to pay distributions even when we record net income, and we may pay distributions during periods when we incur net losses.

The amount of cash that we have available for distribution depends primarily on our cash flow, including cash from reserves and working capital or other borrowings, and not solely on our profitability, which is affected by non-cash items. As a result, we may be unable to pay distributions even when we record net income, and we may pay distributions during periods when we incur net losses.

The amount of available cash we will need to pay the initial quarterly distribution for four quarters on the units to be outstanding immediately after this offering is $18.7 million. If we had completed the transactions contemplated in this prospectus on January 1, 2006, pro forma available cash generated during the year ended December 31, 2006 and the twelve months ended June 30, 2007 would have been approximately $11.9 million and $12.6 million, respectively. This amount of pro forma cash available for distribution would have been sufficient to allow us to pay approximately 64% and 68%, respectively, of the initial quarterly distributions on our units during these periods (59% and 63%, respectively, assuming the underwriters exercise in full their option to purchase additional common units). For a calculation of our ability to make distributions to you based on our pro forma results for the twelve months ending September 30, 2008, please read “Cash Distribution Policy and Restrictions on Distributions” included elsewhere in this prospectus.

If we are unable to achieve the Estimated Adjusted EBITDA set forth in “Cash Distribution Policy and Restrictions on Distributions” and cannot borrow the required amounts, we may be unable to pay the full, or any, amount of the initial quarterly distribution on the common units, in which event the market price of our units may decline substantially.

The Estimated Adjusted EBITDA set forth in “Cash Distribution Policy and Restrictions on Distributions” is for the twelve months ending September 30, 2008. Our management has prepared this information and we have not received an opinion or report on it from any independent accountants. In addition, “Cash Distribution Policy and Restrictions on Distributions” includes a calculation of Estimated Adjusted EBITDA. The assumptions underlying this calculation are inherently uncertain and are subject to significant business, economic, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those expected. For example, because we assume a natural gas price that is higher than the $7.50 per MMBtu price floor in our put options when determining Estimated Adjusted EBITDA, our forecast period only includes the effect of our swap arrangements, which cover 60% of our expected total production during the twelve months ending September 30, 2008. If we do not achieve the expected results or cannot borrow the amounts needed, we may not be able to pay the full, or any, amount of the initial quarterly distribution, in which event the market price of our units may decline substantially.

Our estimated reserves are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

No one can measure underground accumulations of natural gas in an exact way. Natural gas reserve engineering requires subjective estimates of underground accumulations of natural gas and assumptions concerning future 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. Independent petroleum engineers prepare estimates of our proved reserves. Some of our reserve estimates are made without the benefit of a lengthy production history, which are less reliable than estimates based on a lengthy production history. Also, we make certain assumptions regarding future natural gas prices, production levels, and operating and development costs that may prove incorrect. Any significant variance from these assumptions by actual figures could greatly affect our estimates of reserves, the economically recoverable quantities of 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. For example, a $1.00 per MMBtu decrease in natural gas prices for the natural gas prices at March 31, 2007 would reduce the standardized measure of our proved reserves as of March 31, 2007 from $179.8 million to $149.6 million. Our standardized measure is calculated using unhedged natural gas prices and is determined in accordance with the rules and regulations of the Securities and Exchange Commission. Numerous changes over time to the assumptions on which our reserve estimates are based, as described above, often result in the actual quantities of natural gas we ultimately recover being different from our reserve estimates.

The present value of future net cash flows from our proved reserves is not necessarily the same as the current market value of our estimated natural gas reserves. Any material inaccuracies 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 you.

We base the estimated discounted future net cash flows from our proved reserves on prices and costs in effect on the day of the estimate. However, actual future net cash flows from our natural gas properties will be affected by factors such as:

· supply of and demand for natural gas;

· actual prices we receive for natural gas;

· our actual operating costs in providing natural gas;

· the amount and timing of our capital expenditures;

· the amount and timing of actual production; and

· changes in governmental regulations or taxation.

The timing of both our production and our incurrence of expenses in connection with the development and production of natural gas 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 natural gas industry in general. Any material inaccuracies 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 you.

Our operations 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 reserves and adversely affect our ability to make distributions to our unitholders.

The natural gas and oil 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 natural gas reserves. These expenditures will reduce our cash available for distribution. We intend to finance our

future capital expenditures with cash flow from operations and our financing arrangements. Our cash flow from operations and access to capital are subject to a number of variables, including:

· our proved reserves;

· the level of natural gas we are able to produce from existing wells;

· the prices at which our natural gas is sold; and

· our ability to acquire, locate and produce new reserves.

If our revenues or the borrowing base under our reserve-based credit facility decrease as a result of lower natural gas 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 or to replace or add to our reserves. Our reserve-based credit facility restricts our ability to obtain new debt 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 reserve-based 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 and a reduction in our cash available for distribution.

Our business depends on gathering and compression facilities owned by Vinland and transportation facilities owned by Delta Natural Gas, Columbia Gas Transmission and other third-party transporters and we rely on Vinland to gather and deliver our natural gas to certain designated interconnects with third-party transporters. Any limitation in these services or delay in providing interconnections to newly drilled wells would interfere with our ability to market the natural gas we produce and could reduce our revenues and cash available for distribution.

In connection with this offering, on April 18, 2007 but effective as of January 5, 2007, we entered into a gathering and compression agreement with Vinland. Pursuant to this agreement, Vinland will gather, compress, deliver and provide the services necessary for us to market our natural gas production in the area of mutual interest. Vinland will deliver our natural gas production to certain designated interconnects with third-party transporters including Delta Natural Gas and Columbia Gas Transmission. As a result, the marketability of our natural gas production depends in part on the availability, proximity and capacity of Vinland’s, Delta’s, and Columbia’s pipeline systems. The amount of 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, excessive pressure, physical damage to the gathering, compression or transportation system, or lack of contracted 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. In addition, some of our wells are drilled in locations that are not serviced by gathering and transportation pipelines, or the gathering and transportation pipelines in the area may not have sufficient capacity to transport the additional production. As a result, we may not be able to sell the natural gas production from these wells until the necessary gathering and transportation systems are constructed. Any significant curtailment in gathering system or pipeline capacity, or significant delay in the construction of necessary gathering, compression and transportation facilities, could reduce our revenues and cash available for distribution. Finally, if we drill wells in locations that are not serviced by Vinland’s gathering pipelines, we may need to contract with a third-party to deliver our production which may not be as favorable to us as our agreement with Vinland.

Future price declines may result in a write-down of our asset carrying values, which could have a material adverse effect on our results of operations and our ability to borrow funds under our reserve based credit facility, which may adversely affect our ability to make distributions to our unitholders.

Lower natural gas prices may not only decrease our revenues, but also reduce the amount of natural 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 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 result in a material reduction in our results of operations in the period taken and our ability to borrow funds under our reserve-based credit facility, which may affect our ability to fund our operations and acquire additional reserves, which may adversely affect our ability to make cash distributions to our unitholders.

We depend on certain key customers for sales of our natural gas. To the extent these and other customers reduce the volumes of natural gas they purchase from us, our revenues and cash available for distribution could decline.

For the year ended December 31, 2006, sales of natural gas to North American Energy Corporation, Osram Sylvania, Inc., Dominion Field Services, Inc., BP Energy Company and Eagle Energy Partners, LLC accounted for approximately 32%, 13%, 13%, 10% and 7%, respectively, of our total revenues. Our top five purchasers during the year ended December 31, 2006, therefore accounted for 75% of our total revenues. For the six months ended June 30, 2007, these same five purchasers accounted for approximately 95% of our total revenues. To the extent these and other customers reduce the volumes of natural gas that they purchase from us and they are not replaced in a timely manner with a new customer, our revenues and cash available for distribution could decline.

Because we handle natural gas and other petroleum products, we may incur significant costs and liabilities in the future resulting from a failure to comply with new or existing environmental regulations or an accidental release of hazardous substances into the environment.

The operations of our wells are subject to stringent and complex federal, state and local environmental laws and regulations. These include, for example:

· the federal Clean Air Act and comparable state laws and regulations that impose obligations related to air emissions;

· the federal Clean Water Act and comparable state laws and regulations that impose obligations related to discharges of pollutants into regulated bodies of water;

· the federal Resource Conservation and Recovery Act, or RCRA, and comparable state laws that impose requirements for the handling and disposal of waste from our facilities; and

· the Comprehensive Environmental Response, Compensation and Liability Act of 1980, or CERCLA, also known as “Superfund,” and comparable state laws that regulate the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by us or at locations to which we have sent hazardous substances for disposal.

Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements, and the issuance of orders enjoining future operations. Certain environmental statutes, including the RCRA, CERCLA, the federal Oil Pollution Act and analogous state laws and

implementing regulations, impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances or wastes have been disposed of or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property or natural resource damage allegedly caused by the release of hazardous substances or other waste products into the environment.

We may incur significant environmental costs and liabilities due to the nature of our business and the hazardous substances and wastes associated with operation of the wells. For example, an accidental release of petroleum hydrocarbons from one of our wells could subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury, property and natural resource damage, and fines or penalties for related violations of environmental laws or regulations. Moreover, the possibility exists that stricter laws, regulations or enforcement policies could significantly increase our compliance costs and the cost of any remediation that may become necessary. We may not be able to recover some or any of these costs from insurance. Please read “Business—Operations—Environmental Matters and Regulation.”

Our future distributions and proved reserves will be dependent upon the success of our efforts to prudently acquire, manage and develop natural gas and oil properties that conform to the acquisition profile described in this prospectus.

In addition to ownership of the properties currently owned by us, unless we acquire properties in the future containing additional proved reserves or successfully develop proved reserves on our existing properties, our proved reserves will decline as the reserves attributable to the underlying properties are produced. In addition, if the costs to develop or operate our properties increase, the estimated proved reserves associated with properties will be reduced below the level that would otherwise be estimated. We will manage and develop our properties, and the ultimate value to us of such properties which we acquire will be dependent upon the price we pay and our ability to prudently acquire, manage and develop such properties. As a result, our future cash distributions will be dependent to a substantial extent upon our ability to prudently acquire, manage and develop such properties.

Suitable acquisition candidates may not be available on terms and conditions that we find acceptable, and acquisitions pose substantial risks to our businesses, financial conditions and results of operations. Even if future acquisitions are completed, the following are some of the risks associated with acquisitions, which could reduce the amount of cash available from the affected properties:

· some of the acquired properties may not produce revenues, reserves, earnings or cash flow at anticipated levels;

· we may assume liabilities that were not disclosed or that exceed their estimates;

· we may be unable to integrate acquired properties successfully and may not realize anticipated economic, operational and other benefits in a timely manner, which could result in substantial costs and delays or other operational, technical or financial problems;

· acquisitions could disrupt our ongoing business, distract management, divert resources and make it difficult to maintain our current business standards, controls and procedures; and

· we may incur additional debt related to future acquisitions.

Substantial acquisitions or other transactions could require significant external capital and could change our risk and property profile.

A principal component of our business strategy is to grow our asset base and production through the acquisition of natural gas and oil properties characterized by long-lived, stable production. The character

of the newly acquired properties may be substantially different in operating or geological characteristics or geographic location than our existing properties. The changes in the characteristics and risk profiles of such new properties will in turn affect our risk profile, which may negatively affect our ability to issue equity or debt securities in order to fund future acquisitions and may inhibit our ability to renegotiate our existing credit facilities on favorable terms.

Locations that we decide to drill may not yield natural gas in commercially viable quantities.

The cost of drilling, completing and operating a well is often uncertain, and cost factors can adversely affect the economics of a well. Our efforts will be uneconomical if we drill dry holes or wells that are productive but do not produce enough to be commercially viable after drilling, operating and other costs. If we drill future wells that we identify as dry holes, our drilling success rate would decline and may adversely affect our results of operations and our ability to pay future cash distributions at expected levels.

Many of our leases are in areas that have been partially depleted or drained by offset wells.

We believe that many of our leases are in areas that have already been partially depleted or drained by earlier offset drilling. This may inhibit our ability to find economically recoverable quantities of natural gas in these areas.

Our identified drilling location inventories are scheduled out over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling, resulting in temporarily lower cash from operations, which may impact our ability to pay distributions.

Our management has specifically identified and scheduled drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. As reflected in the reserve report, as of March 31, 2007, we had identified 338 proved undeveloped drilling locations and over 171 additional drilling locations. These identified drilling locations represent a significant part of our strategy. Our ability to drill and develop these locations depends on a number of factors, including the availability of capital, seasonal conditions, regulatory approvals, natural gas prices, drilling and operating costs and drilling results. In addition, NSAI has not assigned any proved reserves to the over 171 unproved drilling locations we have identified and scheduled for drilling and therefore greater uncertainty exists with respect to the success of drilling wells at these drilling locations. Our final determination on whether to drill any of these drilling locations will be dependent upon the factors described above as well as, to some degree, the results of our drilling activities with respect to our proved drilling locations. Because of these uncertainties, we do not know if the numerous drilling locations we have identified will be drilled within our expected timeframe or will ever be drilled or if we will be able to produce natural gas from these or any other potential drilling locations. As such, our actual drilling activities may materially differ from those presently identified, which could adversely affect our business.

Drilling for and producing natural gas are high risk activities with many uncertainties that could adversely affect our financial condition or results of operations and, as a result, our ability to pay distributions to our unitholders.

Our drilling activities are subject to many risks, including the risk that we will not discover commercially productive reservoirs. Drilling for natural gas can be uneconomical, not only from dry holes, but also from productive wells that do not produce sufficient revenues to be commercially viable. In addition, our drilling and producing operations may be curtailed, delayed or canceled as a result of other factors, including:

· the high cost, shortages or delivery delays of equipment and services;

· unexpected operational events;

· adverse weather conditions;

· facility or equipment malfunctions;

· title problems;

· pipeline ruptures or spills;

· compliance with environmental and other governmental requirements;

· unusual or unexpected geological formations;

· loss of drilling fluid circulation;

· formations with abnormal pressures;

· fires;

· blowouts, craterings and explosions;

· uncontrollable flows of natural gas or well fluids; and

· pipeline capacity curtailments.

Any of these events can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination, loss of wells and regulatory penalties.

We ordinarily maintain insurance against various losses and liabilities arising from our operations; however, insurance against all operational risks is not available to us. 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 could adversely affect our business activities, financial condition, results of operations and our ability to make cash distributions to you.

None of the proceeds of this offering will be used to maintain or grow our asset base.

None of the proceeds of this offering will be used to maintain or grow our asset base, which will be necessary to cover future distributions. The proceeds of the offering will be used to repay our outstanding debt, pay deferred swap obligations and pay accrued distributions to Nami, management and the Private Investors under our limited liability company agreement. Accordingly, in order to grow our asset base we will need to use cash flow from operations or engage in equity or debt financings to acquire or explore for oil and gas reserves.

We may incur substantial additional debt in the future to enable us to pursue our business plan and to pay distributions to our unitholders. If we use borrowings under our reserve-based credit facility to pay distributions for an extended period of time rather than toward funding capital expenditures and other matters relating to our operations, we may be unable to support or grow our business.

Our business requires a significant amount of capital expenditures to maintain and grow production levels. Commodity prices have historically been volatile, and we cannot predict the prices we will be able to realize for our production in the future. As a result, we may borrow significant amounts under our reserve-based credit facility in the future to enable us to pay quarterly distributions. Significant declines in our production or significant declines in realized natural gas prices for prolonged periods and resulting decreases in our borrowing base may force us to reduce or suspend distributions to our unitholders.

When we borrow to pay distributions, we are distributing more cash than we are generating from our operations on a current basis. This means that we are using a portion of our borrowing capacity under our reserve-based credit facility to pay distributions rather than to maintain or expand our operations. If we

use borrowings under our reserve-based credit facility to pay distributions for an extended period of time rather than toward funding capital expenditures and other matters relating to our operations, we may be unable to support or grow our business. Such a curtailment of our business activities, combined with our payment of principal and interest on our future indebtedness to pay these distributions, will reduce our cash available for distribution on our common units. If we borrow to pay distributions during periods of low commodity prices and commodity prices remain low, we may have to reduce or suspend our distribution in order to avoid excessive leverage.

Our reserve-based credit facility has substantial restrictions and financial covenants and we may have difficulty obtaining additional credit, which could adversely affect our operations and our ability to pay distributions to our unitholders.

We are prohibited from borrowing under our reserve-based credit facility to pay distributions to unitholders if the amount of borrowings outstanding under our reserve-based credit facility reaches or exceeds 50% of the borrowing base. Our borrowing base is the amount of money available for borrowing, as determined semi-annually by our lenders in their sole discretion. The lenders will redetermine the borrowing base based on an engineering report with respect to our natural gas reserves, which will take into account the prevailing natural gas prices at such time. We anticipate that if, at the time of any distribution, our borrowings equal or exceed 50% of the then-specified borrowing base, our ability to pay distributions to our unitholders in any such quarter will be solely dependent on our ability to generate sufficient cash from our operations. As of September 1, 2007, after giving effect to the use of the net proceeds from this offering, we estimate that we will have $13.4 million in outstanding borrowings under the reserve-based credit facility upon the closing of the offering.

The lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under our reserve-based credit facility. Any increase in the borrowing base requires the consent of all the lenders. Outstanding borrowings in excess of the borrowing base must be repaid immediately, or we must pledge other natural gas and oil properties as additional collateral. We do not currently have any substantial unpledged properties, and we may not have the financial resources in the future to make any mandatory principal prepayments required under our reserve-based credit facility.

Seasonal weather conditions and lease stipulations adversely affect our ability to conduct drilling activities in some of the areas where we operate.

Natural gas operations in the Appalachian Basin are adversely affected by seasonal weather conditions, primarily in the spring. Many municipalities impose weight restrictions on the paved roads that lead to our jobsites due to the muddy conditions caused by spring thaws. This limits our access to these jobsites and our ability to service wells in these areas.

Properties that we buy may not produce as projected and we may be unable to determine reserve potential, identify liabilities associated with the properties or obtain protection from sellers against such liabilities.

One of our growth strategies is to capitalize on opportunistic acquisitions of natural gas and oil reserves. However, our reviews of acquired properties are inherently incomplete because it generally is not feasible to review in depth every individual property involved in each acquisition. 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 ground water contamination, are not necessarily observable even when an inspection is undertaken.

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

We enter into hedging arrangements to reduce the impact of natural gas price volatility on our cash flow from operations. Currently, we use a combination of fixed-price TECO swaps and NYMEX put options to hedge natural gas prices. Our fixed-priced swaps in place from July 1, 2007 through 2011 hedge approximately 80% of our expected production from wells producing at March 31, 2007 at a weighted average price of $8.33 per MMBtu. However, as a result of expected production from wells that began or are expected to begin producing after March 31, 2007, our fixed-price TECO swaps hedge approximately 60% of our total production for the twelve month period ending September 30, 2008 at $9.00 per MMBtu. As to production volumes that are subject to our fixed-price TECO swaps, we will not benefit from any increased revenues if the price of natural gas is greater than our fixed-price swap prices. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Quantitative and Qualitative Disclosure about Market Risk.”

Our actual future production may be significantly higher or lower than we estimate at the time we enter into hedging transactions for such period. If the actual amount of production is higher than we estimate, we will have greater commodity price exposure than we intended. If the actual amount of production is lower than the notional 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 hedging 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 hedging 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; and

· the steps we take to monitor our derivative financial instruments may not detect and prevent violations of our risk management policies and procedures

If the Asher lease is terminated or if Nami Resources, LLC’s rights to production under wells in which we have a contract right to receive proceeds from the sale of production are adversely affected, we could lose our contract right to receive proceeds from the sale of production or it could be adversely affected.

Nami Resources, LLC, a subsidiary of our predecessor that was retained by Nami in connection with the Nami Restructuring Plan, has been involved in an ongoing dispute with Asher Land and Mineral Company, Ltd., or Asher, pursuant to which Asher claims that Nami Resources did not correctly calculate the royalties paid to it and that it failed to abide by certain terms of the leases relating to the coordination of oil and gas development with coal development activities. As part of our separation from Vinland, we received from Nami Resources a contract right to receive approximately 99% of the net proceeds, after deducting royalties paid to other parties, severance taxes, third-party transportation costs, costs incurred in the operation of wells and overhead costs, from the sale of production from certain producing oil and gas wells located within the Asher lease, which accounted for approximately 5% of our pro forma proved reserves as of March 31, 2007. The Asher lease and the litigation related thereto were retained by Nami Resources. If the Asher lease is terminated or if Nami Resources’ rights to production under wells in which we have a contract right to receive proceeds from the sale of production are adversely affected, we could lose our contract right to receive proceeds from the sale of production or it could be adversely affected.

We are exposed to credit risk of our customers and counterparties in the ordinary course of our business activities. Any increase in the nonpayment or nonperformance by our customers and/or counterparties could reduce our ability to make distributions to our unitholders.

We are exposed to risks of loss in the event of nonpayment or nonperformance by our customers and by counterparties to our hedging arrangements. Some of our customers and counterparties may be highly leveraged and subject to their own operating and regulatory risks. Even if our credit review and analysis mechanisms work properly, we may experience financial losses in our dealings with other parties. For example, we recently established an approximate $1 million provision for loss for an amount due from a customer who filed for protection under Chapter 11 of the Bankruptcy Code in May 2007. Any increase in the nonpayment or nonperformance by our customers and/or counterparties could reduce our ability to make distributions to our unitholders.

Our related party agreements with Vinland may not contain the most competitive terms available to us.

On April 18, 2007 but effective January 5, 2007, we entered into several agreements with Vinland pursuant to which Vinland will operate all of our existing wells and coordinate our development drilling program and provide management services to us. The terms of each of these agreements were negotiated between us and Vinland. Because these agreements were negotiated prior to the adoption of our ethics policy, they were not approved by our Conflicts Committee as contemplated by that policy. Because of our related party affiliation with Vinland, these agreements, and future agreements with Vinland, may not contain the most competitive terms available to us. In addition, by purchasing a common unit, a unitholder will become bound by the provisions of our limited liability company agreement, including the related party agreements provided for therein, and a unitholder will be deemed to have consented to some actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable law.

We have a limited number of employees and are dependent on Vinland to manage our operations and provide administrative services.

We have four full time employees, each of whom is located in Houston, Texas while our operations are located in southeast Kentucky and northeast Tennessee. Due to our limited personnel and their location, we rely on Vinland to operate our assets and perform other administrative services for us such as production accounting, land administration and engineering. Vinland conducts businesses and activities of its own in which we 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 of Vinland who provide services to us. If the officers and employees of Vinland 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 depend on senior management personnel, each of whom would be difficult to replace. The loss of any of Messrs. Smith, Robert or Pence could negatively impact our ability to execute our strategy and our results of operations.

We depend on the performance of Scott W. Smith, our President and Chief Executive Officer, Richard A. Robert, our Executive Vice President and Chief Financial Officer, and Britt Pence, our Vice President of Engineering. We do not maintain key person insurance for any of Messrs. Smith,. Robert or Pence. The loss of any of these officers could negatively impact our ability to execute our strategy and our results of operations.

We may be unable to compete effectively with larger companies, which may adversely affect our ability to generate sufficient revenue to allow us to pay distributions to our unitholders.

The natural gas and oil industry is intensely competitive, and we compete with other companies that have greater resources. 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 natural gas and oil, 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 natural gas and oil prices and to absorb the burden of present and future federal, state, local and other laws and regulations. Our inability to compete effectively with larger companies could materially affect on our business activities, financial condition and results of operations, which could reduce the amount of cash we have available to pay distributions to you.

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

Our operations are regulated extensively at the federal, state and local levels. Environmental and other governmental laws and regulations have increased the costs to plan, design, drill, install, operate and abandon natural gas and oil wells. Under these laws and regulations, we could also be liable for personal injuries, property damage and other damages. Failure to comply with these laws and regulations may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Moreover, public interest in environmental protection has increased in recent years, and environmental organizations have opposed, with some success, certain drilling projects.

Part of the regulatory environment in which we operate includes, in some cases, legal requirements for obtaining environmental assessments, environmental impact studies and/or plans of development before commencing drilling and production activities. In addition, our activities are subject to the regulations regarding conservation practices and protection of correlative rights. These regulations affect our operations and limit the quantity of natural gas we may produce and sell. A major risk inherent in our drilling plans is the need to obtain drilling permits from state and local authorities. Delays in obtaining regulatory approvals or drilling permits, the failure to obtain a drilling permit for a well or the receipt of a permit with unreasonable conditions or costs could adversely affect our ability to develop our properties. Additionally, the natural gas and oil regulatory environment could change in ways that might substantially increase the financial and managerial costs of compliance with these laws and regulations and, consequently, adversely affect our profitability. At this time, we cannot predict the effect of this increase on our results of operations. Furthermore, we may be put at a competitive disadvantage to larger companies in our industry who can spread these additional costs over a greater number of wells and larger operating staff. Please read “Business—Operations—Environmental Matters and Regulation” and “Business—Operations—Other Regulation of the Natural Gas and Oil Industry” for a description of the laws and regulations that affect us.

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

Higher natural gas prices generally increase the demand for drilling rigs, supplies, services, equipment and crews, and can lead to shortages of, and increasing costs for, drilling equipment, services and personnel. Over the past three years, we and other natural gas and oil companies have experienced higher drilling and operating costs. Shortages of, or increasing costs for, experienced drilling crews and equipment and services could restrict our ability to drill the wells and conduct the operations that 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.

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

We rely exclusively on sales of the natural gas and oil that we produce. Furthermore, all of our assets are located in the southern portion of the Appalachian Basin. Due to our lack of diversification in asset type and location, an adverse development in the natural gas business in this geographic area 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.

Risks Related to Our Structure

Mr. Nami, who together with certain of his affiliates and related persons, will own approximately 29.7% of our outstanding common units after this offering, and certain members of our board of directors who are officers or directors of Vinland Energy Eastern may have conflicts of interest with us. The ultimate resolution of these conflicts of interest may result in favoring the interests of these other parties over yours and may be to our detriment. Our limited liability company agreement limits the remedies available to you in the event you have a claim relating to conflicts of interest.

Following the offering, two members of our board of directors will be officers or directors or affiliates of Vinland, of which Nami owns approximately 90%. Conflicts of interest may arise between Nami and his affiliates, including Vinland, and certain members of our board of directors, on the one hand, and us and our unitholders, on the other hand. These potential conflicts may relate to the divergent interests of these parties. Situations in which the interests of Nami and his affiliates, including Vinland, and certain members of our board of directors may differ from interests of owners of units include, among others, the following situations:

· our limited liability company agreement gives our board of directors broad discretion in establishing cash reserves for the proper conduct of our business, which will affect the amount of cash available for distribution. For example, our board of directors will use its reasonable discretion to establish and maintain cash reserves sufficient to fund our drilling program;

· none of our limited liability company agreement, management services agreement, participation agreement nor any other agreement requires Nami or any of his affiliates, including Vinland, to pursue a business strategy that favors us. Directors and officers of Vinland and its subsidiaries have a fiduciary duty while acting in the capacity as such director or officer of Vinland or such subsidiary to make decisions in the best interests of the members or stockholders of Vinland, which may be contrary to our best interests;

· we rely on Vinland to operate and develop our properties;

· we depend on Vinland to gather, compress, deliver and provide services necessary for us to market our natural gas production;

· we intend to rely on Vinland to provide us with opportunities for the acquisition of natural gas and oil reserves, but Vinland does not have an obligation to provide us with such opportunities; and

· Nami and his affiliates, including Vinland, and the Private Investors, are not prohibited from investing or engaging in other businesses or activities that compete with us.

resolving conflicts of interest, you will not be able to assert that such resolution constituted a breach of fiduciary duty owed to us or to you by our board of directors and officers.

You will experience immediate and substantial dilution of $14.45 per common unit.

The initial public offering price of $23.00 per common unit exceeds our pro forma net tangible book value of $8.55 per common unit. Based on an assumed initial public offering price of $23.00, you will incur immediate and substantial dilution of $14.45 per common unit. The main factor causing dilution is that Nami, the Private Investors and certain members of our management acquired interests in us at equivalent per unit prices lower than the public offering price. Please read “Dilution.”

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

We may issue an unlimited number of limited liability company interests of any type, including units, without the approval of our unitholders.

The issuance of additional units or other equity securities may have the following effects:

· your proportionate ownership interest in us may decrease;

· the amount of cash distributed on each unit may decrease;

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

· the market price of the units may decline.

Our limited liability company agreement restricts the voting rights of unitholders owning 20% or more of our units.

Our limited liability company agreement restricts the voting rights of unitholders by providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than Nami and his affiliates or transferees and persons who acquire such units with the prior approval of the board of directors, cannot vote on any matter. Our limited liability 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 unitholders’ ability to influence the manner or direction of management.

Our limited liability company agreement prohibits a unitholder who acquires 15% or more of our common units without the approval of our board of directors from engaging in a business combination with us for three years. This provision could discourage a change of control that our unitholders may favor, which could negatively affect the price of our common units.

Our limited liability company agreement effectively adopts Section 203 of the Delaware General Corporation Laws, or the DGCL. Section 203 of the DGCL as it applies to us prevents an interested unitholder, defined as a person who owns 15% or more of our outstanding common units, from engaging in business combinations with us for three years following the time such person becomes an interested unitholder. Section 203 broadly defines “business combination” to encompass a wide variety of transactions with or caused by an interested unitholder, including mergers, asset sales and other transactions in which the interested unitholder receives a benefit on other than a pro rata basis with other unitholders. This provision of our limited liability company agreement could have an anti-takeover effect with respect to transactions not approved in advance by our board of directors, including discouraging takeover attempts that might result in a premium over the market price for our common units.

Our limited liability company agreement provides for a limited call right that may require you to sell your units at an undesirable time or price.

If, at any time, any person owns more than 90% of the units then outstanding, such person has 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 remaining units then outstanding at a price not less than the then-current market price of the units. As a result, you may be required to sell your units at an undesirable time or price and therefore may receive a lower or no return on your investment. You may also incur tax liability upon a sale of your units. For additional information about the call right, please read “The Limited Liability Company Agreement—Limited Call Right.”

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

Prior to the offering, there has been no public market for common units. After the offering, there will be 5,000,000 publicly traded common units (5,750,000 common units if the underwriters’ option is exercised in full). 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.

If our common unit price declines after the initial public offering, you could lose a significant part of your investment.

The market price of our common units could be subject to wide fluctuations in response to a number of factors, most of which we cannot control, including:

· changes in securities analysts’ recommendations and their estimates of our financial performance;

· the public’s reaction to our press releases, announcements and our filings with the Securities and Exchange Commission;

· fluctuations in broader securities market prices and volumes, particularly among securities of natural gas and oil companies and securities of publicly traded limited partnerships and limited liability companies;

· changes in market valuations of similar companies;

· departures of key personnel;

· commencement of or involvement in litigation;

· variations in our quarterly results of operations or those of other natural gas and oil companies;

· variations in the amount of our quarterly cash distributions;

· future issuances and sales of our units; and

· changes in general conditions in the U.S. economy, financial markets or the natural gas and oil industry.

In recent years, the securities market has experienced extreme price and volume fluctuations. This volatility has had a significant effect on the market price of securities issued by many companies for reasons unrelated to the operating performance of these companies. Future market fluctuations may result in a lower price of our common units.

Nami and the Private Investors may sell common units in the future, which could reduce the market price of our outstanding common units.

Following the completion of this offering, Nami and the Private Investors will hold an aggregate of 5,540,000 common units. We have agreed to register for sale common units held by Nami. These registration rights allow Nami to request registration of his units and to include any of those common units in a registration of other securities by us. In addition, we have entered into a registration rights agreement

with the Private Investors, which requires us to file with the SEC a registration statement within 90 days of the closing of this offering and to have such registration statement become effective within 180 days of the closing of this offering. Following the effective date of the registration statement and the expiration of any lock-up agreements applicable to the Private Investors, these holders may sell their units into the public markets. For a description of the registration rights agreement, please read “Units Eligible for Future Sale.” In addition, Nami or the Private Investors may transfer their common units to a third-party without the consent of our unitholders. Furthermore, there is no restriction in our limited liability company agreement on the ability of Nami to cause a transfer to a third-party of its affiliates’ equity interest in Vinland.

Unitholders may have liability to repay distributions.

Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 18-607 of the Delaware Revised Limited Liability Company Act (the “Delaware 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 an impermissible distribution, members or unitholders who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited liability company for the distribution amount. A purchaser of common units who becomes a member or unitholder is liable for the obligations of the transferring member to make contributions to the limited liability company that are known to such purchaser of units at the time it became a member and for unknown obligations if the liabilities could be determined from our limited liability company agreement.

Tax Risks to 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 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 IRS were to treat us as a corporation for federal income tax purposes or we were to become subject to entity-level taxation for state tax purposes, taxes paid, if any, would reduce the amount of cash available for distribution to you.

The anticipated after-tax economic benefit of an investment in our 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 IRS on this or any other tax matter that affects us.

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 rates, currently at a maximum rate 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, gain, loss, deduction or credit would flow through to you. Because a tax may be imposed on us as a corporation, our cash available for distribution to our unitholders could be reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our common units.

Current law or our business 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, in response to certain recent developments, members of Congress are considering substantive changes to the existing federal income tax laws that affect publicly traded partnerships that could eliminate partnership tax treatment for certain publicly traded partnerships. 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 common units. In addition, because of widespread state budget deficits and other reasons, several

states are evaluating ways to subject partnerships and limited liability companies to entity-level taxation through the imposition of state income, franchise or other forms of taxation. If any state were to impose a tax upon us as an entity, the cash available for distribution to you would be reduced.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular common 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 common units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration 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. Please read “Material Tax Consequences—Disposition of Units—Allocations Between Transferors and Transferees.”

If the IRS contests the federal income tax positions we take, the market for our units may be adversely impacted and the costs of any IRS contest will reduce our cash available for distribution.

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 that affects 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 and a court may disagree with some or all of those positions. Any contest with the IRS may materially and adversely impact the market for our units and the price at which they trade. In addition, our costs of any contest with the IRS will result in a reduction in cash available for distribution to our unitholders and thus will be borne indirectly by our unitholders.

You may be required to pay taxes on income from us even if you do not receive any cash distributions from us.

You will be required to pay federal income taxes and, in some cases, state and local income taxes on your share of our taxable income, whether or not you receive 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 actual tax liability that results from your share of our taxable income.

Tax gain or loss on disposition of our 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 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 depreciation recapture. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if you sell your units, you may incur a tax liability in excess of the amount of cash you receive from the sale. Please read “Material Tax Consequences—Disposition of Units—Recognition of Gain or Loss” for a further discussion of the foregoing.

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

Investment in units by tax-exempt entities, including employee benefit plans and individual retirement accounts (known as IRAs), and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, will be unrelated business taxable income and will be taxable to such a unitholder. Distributions to non-U.S. persons will be reduced by withholding taxes imposed at the highest effective applicable tax rate, and non-U.S. persons will be required to file United States federal income tax returns and pay tax on their share of our taxable income. If you are a tax exempt entity or a foreign person, you should consult your tax advisor before investing in our units.

We will treat each purchaser of our common units as having the same tax benefits without regard to the actual 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 adopt depreciation and amortization positions that may not conform with all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain on the sale of common units and could have a negative impact on the value of our common units or result in audits of and adjustments to our unitholders’ tax returns. Please read “Material Tax Consequences—Uniformity of Units” for a further discussion of the effect of the depreciation and amortization positions we will adopt.

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 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. Our termination would, among other things, result in the closing of our taxable year for all unitholders and could result in a deferral of depreciation deductions allowable in computing our taxable income. Please read “Material Tax Consequences—Disposition of Units—Constructive Termination” for a discussion of the consequences of our termination for federal income tax purposes.

You may be subject to state and local taxes and return filing requirements in states where you 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 reside 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 conduct business and own assets in Kentucky and Tennessee. Both of these states currently impose a personal income tax on individuals and an entity level tax on certain corporations and other entities. As we make acquisitions or expand our business, we may conduct business or own assets in other states in the future. It is the responsibility of each unitholder to file all United States federal, foreign, state and local tax returns that may be required of such unitholder. Our counsel has not rendered an opinion on the state or local tax consequences of an investment in our common units.

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This prospectus contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control, which may include statements about our:

· the volatility of realized natural gas and oil prices;

· discovery, estimation, development and replacement of natural gas and oil reserves;

· business and financial strategy;

· drilling locations;

· technology;

· cash flow, liquidity and financial position;

· production volumes;

· lease operating expenses, selling, general and administrative costs and finding and development costs;

· availability of drilling and production equipment, labor and other services;

· future operating results;

· prospect development and property acquisitions;

· the rate of development of our existing undeveloped leasehold acreage;

· marketing of natural gas and oil;

· competition in the natural gas and oil industry;

· the impact of weather and the occurrence of natural disasters such as fires, floods and other catastrophic events and natural disasters;

· governmental regulation of the natural gas and oil industry;

· developments in oil-producing and natural gas producing countries; and

· strategic plans, objectives, expectations and intentions for future operations.

All of these types of statements, other than statements of historical fact included in this prospectus, are forward-looking statements. These forward-looking statements may be found in the “Prospectus Summary,” “Risk Factors,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Business” and other sections of this prospectus. In some cases, you can identify forward-looking statements by terminology such as “may,” “will,” “could,” “should,” “expect,” “plan,” “project,” “intend,” “anticipate,” “believe,” “estimate,” “predict,” “potential,” “pursue,” “target,” “continue,” the negative of such terms or other comparable terminology.

The forward-looking statements contained in this prospectus are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In addition, management’s assumptions about future events may prove to be inaccurate. Management cautions all readers that the forward-looking statements contained in this prospectus are not guarantees of future performance, and we cannot assure any reader that such statements will be realized or the forward-looking events and circumstances will occur. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to factors listed in the “Risk Factors” section and elsewhere in this prospectus. All forward-looking statements speak only as of the date of this prospectus. We do not intend to publicly update or revise any forward-looking statements as a result of new information, future events or otherwise. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

USE OF PROCEEDS

The following table sets forth the estimated sources and uses of the funds we expect to receive from the sale of common units in this offering and related transactions. The actual sources and uses of these funds may differ from those set forth below.

Sources of Funds			Uses of Funds
(in millions)			(in millions)
Sale of 5,000,000 common units(1)	$	107.0	Repayment of indebtedness(2)	$	94.4
			Distribution to Nami and managment(3)	2.7
			Distribution to Private Investors(3)	1.6
			Pay deferred swap obligation(4)	7.3
			Pay expenses associated with the offering	1.0
				$	107.0

(1) We expect to receive net proceeds of approximately $107.0 million from the sale of 5,000,000 common units offered by this prospectus, after deducting the underwriting discounts. Our estimates assume an initial offering price of $23.00 per unit and no exercise of the underwriters’ option to purchase additional common units. An increase or decrease in the initial public offering price of $1.00 per common unit would cause the net proceeds from the offering, after deducting underwriting discounts and fees and offering expenses payable by us, to increase or decrease by $4.7 million.

(2) As of June 30, 2007, we had $109.0 million outstanding under our reserve-based credit facility. Our credit facility matures on January 3, 2011 and as of June 30, 2007 bore interest at 7.32% per year. As of September 1, 2007, our borrowing base was $112.5 million, of which $107.8 million was outstanding as of that date. We used the borrowings under the reserve-based credit facility to:

· repay approximately $98.5 million of outstanding long-term debt and associated interest and pre-payment fees;

· pay $2.4 million for the termination of existing hedge obligations for 2007;

· purchase $6.5 million in natural gas put options with respect to 5,407,985 MMBtu of production from February 2007 through 2009;

· pay expenses incurred in connection with the closing of the reserve-based credit facility; and

· fund working capital requirements.

(3) $4.3 million of accrued and unpaid distributions to Nami, management and the Private Investors under our limited liability company agreement.

(4) $7.3 million due to counterparty for resetting our natural gas swap contracts for 2007, 2008 and 2009 at higher prices in May 2007.

We will use the net proceeds, if any, from the exercise of the underwriters’ option to further reduce our outstanding borrowings under our reserve-based credit facility.

An affiliate of Citi, an underwriter for this offering, is a lender under our reserve-based credit facility and will be partially repaid with a portion of the net proceeds from this offering. Please read “Underwriting.”

CAPITALIZATION

The following table shows:

· our historical capitalization as of June 30, 2007;

· our pro forma capitalization as of June 30, 2007 to give effect to this offering of common units and the application of the net proceeds, including the repayment of $94.4 million borrowed under our reserve-based credit facility, the payment of accrued distributions, as well as other uses 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 audited historical and unaudited pro forma consolidated 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.”

	As of June 30, 2007
	Historical				Pro Forma As Adjusted
	(unaudited)				(unaudited)
	(in thousands)
Cash and cash equivalents		$	4,445			$	4,445
Reserve-based credit facility		109,000				14,623
Members’ equity:
Units held by public(1)		—				104,378
Units held by Nami, Private Investors and management(2)		(6,063		)		(10,313		)
Total capitalization		$	102,937			$	108,688

(1) Assumes a public offering price of our common units of $23.00 per unit and reflects members’ capital of common unitholders from the net proceeds of this offering of approximately $107.0 million, including approximately $8.0 million of underwriters’ discounts, commissions, fees and other offering expenses payable by us and the application of the proceeds as described in “Use of Proceeds.” A 1,000,000 unit increase in the number of common units issued to the public would result in a $21.4 million increase in the public unitholders’ members’ equity and a $21.4 million decrease in the members’ equity of Nami, Private Investors and management. If the initial public offering price were to increase or decrease by $1.00 per unit, then our cash available to reduce borrowings under our reserve-based credit facility would increase or decrease by $4.7 million.

(2) Includes 240,000 Class B units issued to Scott W. Smith, our President and Chief Executive Officer, 125,000 Class B units issued to Richard A. Robert, our Executive Vice President and Chief Financial Officer, 50,000 Class B units issued to Britt Pence, our Vice President of Engineering, 5,000 Class B units issued to Patty Avila-Eady, our Financial Reporting Manager and the issuance of 40,000 common units to future employees and/or board members following the completion of this offering.

Dilution

Dilution is the amount by which the offering price paid by the purchasers of units sold in this offering will exceed the net tangible book value per unit after the offering. Net tangible book value is our total tangible assets less total liabilities. Assuming an initial public offering price of $23.00 per common unit, on a pro forma basis as of June 30, 2007, after giving effect to the offering of units and the application of the related net proceeds, our net tangible book value was $94.1 million, or $8.55 per common unit. Purchasers of units in this offering will experience substantial and immediate dilution in net tangible book value per unit for accounting purposes, as illustrated in the following table:

Assumed initial public offering price per unit				$	23.00
Pro forma net tangible book value per unit before the offering(1)	$	(1.01	)
Increase in net tangible book value per unit attributable to purchasers in the offering	9.56
Less: Pro forma net tangible book value per unit after the offering(2)				8.55
Immediate dilution in net tangible book value per unit to new investors(3)				$	14.45

(1) Determined by dividing the total number of units held by Nami (3,250,000 common units) and certain members of our management (420,000 Class B units and 40,000 common units to be issued to employees and/or directors following the completion of this offering) and Private Investors (2,290,000 common units) into our net tangible book value.

(2) Determined by dividing the total number of common units to be outstanding after this offering (11,000,000 common and Class B units) into our pro forma net tangible book value, after giving effect to the application of the expected net proceeds of this offering.

(3) If the initial public offering price were to increase or decrease by $1.00 per unit, then dilution or accretion in net tangible book value per unit would equal $4.7 million.

The following table sets forth the number of units that we will issue and the total consideration contributed to us by Nami, certain members of our management and the Private Investors, upon consummation of the transactions contemplated by this prospectus:

	Units Acquired				Total Consideration
	Number	Percent			Amount				Percent
					(in millions)
Nami, certain members of our management and the Private Investors(1)	6,000,000		54.5	%		$	(6.1	)		(6	)%
Purchasers in this offering	5,000,000		45.5	%		115.0				106	%
Total	11,000,000		100.0	%		$	108.9			100.0	%

(1) Includes 240,000 Class B units issued to Scott W. Smith, our President and Chief Executive Officer, 125,000 Class B units issued to Richard A. Robert, our Executive Vice President and Chief Financial Officer, 50,000 Class B units issued to Britt Pence, our Vice President of Engineering, 5,000 Class B units issued to Patty Avila-Eady, our Financial Reporting Manager and the issuance of 40,000 common units to future employees and/or board members following the completion of this offering. The total consideration for all of the units is equal to the net tangible book value as of June 30, 2007 contributed by Nami, certain members of our management and the Private Investors.

CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS

You should read the following discussion of our cash distribution policy in conjunction with the specific assumptions included in this section. For more detailed information regarding the factors and assumptions upon which our cash distribution policy is based, please see “—Estimated Cash Available to Pay Distributions for the Twelve Months Ended September 30, 2008—Estimated Adjusted EBITDA” below. In addition, you should read “Cautionary Note Regarding 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 results of operations, you should refer to our historical and unaudited pro forma consolidated financial statements for the year ended December 31, 2006 included elsewhere in this prospectus as well as “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

General

Our Cash Distribution Policy

Our limited liability company agreement, as amended to be effective at the closing of this offering, provides for the distribution of available cash on a quarterly basis. Available cash, which is defined in the limited liability company agreement attached as Appendix A and the glossary attached as Appendix B hereto, for any quarter consists of cash on hand at the end of that quarter, plus working capital borrowings made after the end of the quarter, less cash reserves, which may include reserves to provide for our future operations, future capital expenditures, future debt service requirements and future cash distributions to our unitholders. Please read “How We Make Cash Distributions—Definition of Available Cash.” The amount of available cash will be determined by our board of directors for each calendar quarter of our operations after the closing of this offering. Our limited liability company agreement may only be amended with the approval of a unit majority.

Rationale for our Cash Distribution Policy

Our cash distribution policy reflects a basic judgment that our unitholders will be better served by distributing our available cash rather than retaining it. It is the current policy of our board of directors that we should increase our level of quarterly cash distributions per unit only when, in its judgment, it believes that (i) we have sufficient reserves and liquidity for the proper conduct of our business, including the maintenance of our asset base, and (ii) we can maintain such an increased distribution level for a sustained period. While this is our current policy, our board of directors may alter such policy in the future when and if it determines such alteration to be appropriate. The amount of available cash will be determined by our board of directors for each calendar quarter after the closing of the offering and will be based upon recommendations from our management. Because we believe we will generally finance any expansion capital expenditures from external financing sources, we believe that our investors are best served by our distributing all of our available cash. In addition, since we are not subject to an entity-level federal income tax, we have more cash to distribute to you than would be the case if we were subject to federal income tax. Our cash distribution policy is consistent with the terms of our limited liability company agreement, which requires that we distribute all of our available cash quarterly. Under that policy, we will pay an initial quarterly distribution of $0.425 per common unit for each complete quarter. These distributions will not be cumulative. Consequently, if distributions on our common units are not paid with respect to any fiscal quarter at the anticipated initial quarterly distribution rate, our unitholders will not be entitled to receive such payments in the future. We are a recently formed limited liability company and have not historically made any cash distributions. Please read “How We Make Cash Distributions.”

Restrictions and Limitations on Our Ability to Make Quarterly Distributions

There is no guarantee that unitholders will receive quarterly distributions from us or that we can or will maintain any increases in our quarterly cash distributions. Our distribution policy may be changed at any time and is subject to limitations and restrictions, including:

· Other than the obligation under our limited liability company agreement to distribute available cash on a quarterly basis, which is subject to our board of directors’ authority to establish reserves and other limitations, our unitholders have no contractual or other legal right to receive distributions.

· Our board of directors will have broad discretion to establish reserves for the prudent conduct of our business. The establishment of those reserves could result in a reduction in the amount of cash available to pay distributions.

· Our ability to make distributions of available cash will depend primarily on our cash flow from operations which primarily depends on our level of production and our realized natural gas prices. Although our limited liability company agreement provides for quarterly distributions of available cash, we have no prior history of making distributions to our members.

· Our distribution policy will be subject to restrictions on distributions under our reserve-based credit facility. Specifically, our reserve-based credit facility prohibits us from making quarterly distributions if our borrowing base utilization exceeds 50%, or will exceed 50% as a result of the distribution, or if a borrowing base deficiency exists on the last day of each quarter. Should we be unable to satisfy these restrictions or another default or event of default occurs and is continuing under our credit agreements, we would be prohibited from making a distribution to you notwithstanding our stated distribution policy. Further, we may enter into future debt arrangements that could subject our ability to pay distributions to compliance with certain tests or ratios or otherwise restrict our ability to pay distributions.

· Even if we do not modify our cash distribution policy, the amount of distributions we pay and the decision to make any distribution will be determined by our board of directors, taking into consideration the terms of our limited liability company agreement.

· Under Section 18-607 of the Delaware Limited Liability Company Act, we may not make a distribution to you if the distribution would cause our liabilities to exceed the fair value of our assets.

· Although our limited liability company agreement requires us to distribute our available cash, our limited liability company agreement, including the provisions requiring us to make cash distributions contained therein, may be amended with the approval of a majority of the outstanding common units. Following completion of this offering, Nami and certain members of our management will own approximately 29.7% and 3.8%, respectively, of the outstanding common units (27.8% and 3.6% respectively, assuming full exercise of the underwriters’ option to purchase additional units).

Our ability to make distributions to our unitholders depends on the performance of our subsidiaries and their ability to distribute funds to us. The ability of our subsidiaries to make distributions to us may be restricted by, among other things, the provisions of existing and future indebtedness, applicable state limited liability company laws and other laws and regulations, including state laws and policies affecting our natural gas and oil production, gathering and marketing operations.

Our Cash Distribution Policy Limits our Ability to Grow

Because we distribute our available cash, our growth may not be as significant as businesses that reinvest their available cash to expand ongoing operations. If we issue additional units or incur debt to fund acquisitions and expansion and investment capital expenditures, the payment of distributions on those additional units or interest on that debt could increase the risk that we will be unable to maintain or

increase our per unit distribution level. There are no limitations in our limited liability company agreement on our ability to issue additional units, including units ranking senior to the units offered in this offering.

Our Ability to Grow is Dependent on our Ability to Access External Expansion Capital

Because we will distribute our available cash from operations to our unitholders each quarter in accordance with the terms of our limited liability company agreement, we will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund any expansion capital expenditures. As a result, to the extent we are unable to finance growth externally, our cash distribution policy will significantly impair our ability to grow our capital asset base.

Our Initial Quarterly Distribution Rate

The amount of the initial quarterly distribution will be $0.425 per unit, or $1.70 per year to the extent we generate sufficient available cash to make such distribution. The amount of available cash, which we also refer to as cash available to pay distributions, needed to pay the initial quarterly distribution on all of the units to be outstanding immediately after this offering for one quarter and for four quarters will be approximately:

	No Exercise of the Underwriters’ Option to Purchase Additional Units					Full Exercise of the Underwriters’ Option to Purchase Additional Units
		Initial Quarterly Distribution					Initial Quarterly Distribution
	Number of Units	One Quarter		Four Quarters		Number of Units	One Quarter		Four Quarters
Distributions to public unitholders	5,000,000	$	2,125,000	$	8,500,000	5,750,000	$	2,443,750	$	9,775,000
Distributions to Private Investors	2,290,000	973,250		3,893,000		2,290,000	973,250		3,893,000
Distributions to Nami	3,250,000	1,381,250		5,525,000		3,250,000	1,381,250		5,525,000
Distributions to management(1)	460,000	195,500		782,000		460,000	195,500		782,000
Total distributions paid	11,000,000	$	4,675,000	$	18,700,000	11,750,000	$	4,993,750	$	19,975,000

(1) Includes 240,000 Class B units issued to Scott W. Smith, our President and Chief Executive Officer, 125,000 Class B units issued to Richard A. Robert, our Executive Vice President and Chief Financial Officer, 50,000 Class B units issued to Britt Pence, our Vice President of Engineering, 5,000 Class B units issued to Patty Avila-Eady, our Financial Reporting Manager and the issuance of 40,000 common units to future employees and/or board members following the completion of this offering. The remaining Class B units have been reserved for additional management personnel that we intend to hire in the future. This does not include the 175,000 options to be granted to management at the time of our initial public offering under our Long-Term Incentive Plan.

We will pay the initial quarterly distribution on all of our outstanding units for each quarter through September 30, 2008 to the extent we generate sufficient available cash to make such distribution. Within 45 days after the end of each quarter, beginning with the quarter ending December 31, 2007, we will distribute all of our available cash to unitholders of record on the applicable record date. We will adjust the initial quarterly distribution for the period from the closing of the offering through December 31, 2007 based on the actual length of that period.

In the sections that follow, we present in detail the basis for our belief that we will have sufficient available cash to pay the initial quarterly distribution on all of our outstanding units for each quarter through September 30, 2008. In those sections, we present two tables:

· “Estimated Adjusted EBITDA,” in which we present our Estimated Adjusted EBITDA for the twelve months ending September 30, 2008. In the footnotes to this first table and in the description of assumptions and considerations described beneath the tables, we present the significant assumptions and considerations underlying our belief that we will generate sufficient Estimated Adjusted EBITDA to pay the initial quarterly distribution on all outstanding units for each quarter through September 30, 2008; and

· “Unaudited Pro Forma Cash Available to Pay Distributions for the Year Ended December 31, 2006 and the Twelve Months Ended June 30, 2007,” in which we present the amount of available cash we would have generated on a pro forma basis for the year ended December 31, 2006 and the twelve months ended June 30, 2007.

Financial Forecast

For the purpose of this offering, our management has prepared the prospective financial information set forth in “—Estimated Cash Available to Pay Distributions for the Twelve Months Ended September 30, 2008” below, and such information is the responsibility of our management. Our forecast information presents, to our best knowledge and belief, our expected results of operations and cash flows for the twelve-month period ending September 30, 2008. Our forecast financial information reflects our judgment as of the date of this prospectus of conditions we expect to exist and the course of action we expect to take during the twelve months ending September 30, 2008. The assumptions disclosed in the footnotes to the table under the caption “—Estimated Cash Available to Pay Distributions for the Twelve Months Ended September 30, 2008—Estimated Adjusted EBITDA” below and the assumptions and considerations described beneath the table are those that we believe are significant to our forecasted information, but we can give you no assurance that the assumptions we make will be realized or that our forecast results will be achieved. There will likely be differences between our forecast and actual results, and those differences could be material. If the forecast is not achieved, we may not be able to pay the full initial quarterly distribution or any amount on our outstanding common units for the twelve months ended September 30, 2008.

Our forecast financial information is a forward-looking statement and should be read together with the historical and pro forma financial statements and the accompanying notes included elsewhere in this prospectus and together with “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” In the view of our management, however, such information was prepared on a reasonable basis, reflects the best currently available estimates and judgments, and presents, to the best of management’s knowledge and belief, the assumptions and considerations on which we base our belief that we can generate the Estimated Adjusted EBITDA necessary for us to have sufficient available cash for distribution to pay a distribution on the units at the initial quarterly distribution rate. However, this information is not factual 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.

Neither our 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 in this section, nor have they expressed any opinion or any other form of assurance on such information or its achievability, and they assume no responsibility for the prospective financial information. Such independent registered public accounting firms’ reports included elsewhere in this prospectus relate to the appropriately described historical financial information contained in this section. Such reports do not extend to the tables and related information contained in this section and should not be read to do so. In addition, such tables and information were not prepared with a view toward compliance with the guidelines established by the American Institute of Certified Public Accountants for preparation and presentation of prospective financial information or in accordance with GAAP.

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 to reflect events or circumstances after the date in this prospectus. Therefore, you are cautioned not to place undue reliance on this information.

As a result of the factors described in “—Estimated Cash Available to Pay Distributions for the Twelve Months Ended September 30, 2008,” in the footnotes to the table in that section and in the assumptions and considerations described beneath the table in that section, we believe we will be able to pay distributions at the

initial quarterly distribution rate of $0.425 per unit on all outstanding units for each full calendar quarter in the twelve-month period ending September 30, 2008.

Estimated Cash Available to Pay Distributions for the Twelve Months Ended September 30, 2008

In order to pay the initial quarterly distribution of $0.425 per unit per quarter for the twelve months ending September 30, 2008, our cumulative cash available to pay distributions must be at least $18.7 million ($20.0 million if the underwriters option to purchase additional common units is exercised in full) over that period. We estimate that our minimum adjusted EBITDA for the twelve-month period ending September 30, 2008 must be at least $32.6 million ($33.0 million if the underwriters option to purchase additional common units is exercised in full) in order to generate cash available for distribution to the holders of our units of approximately $18.7 million ($20.0 million if the underwriters option to purchase additional common units is exercised in full) over that period. We believe we will generate estimated adjusted EBITDA of $35.7 million for the twelve months ending September 30, 2008. We refer to this amount as “Estimated Adjusted EBITDA.” 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. Although we believe that we will be able to achieve these results based on the assumptions and considerations set forth later in this section, we can give you no assurance that we will actually generate the Estimated Adjusted EBITDA and estimated cash available needed to pay the initial quarterly distribution through September 30, 2008. There will likely be differences between these amounts and our actual results and those differences could be material. If our estimate is not achieved, we may not be able to pay the initial quarterly distribution on all our units.

We define adjusted EBITDA as net income (loss) plus:

· Net interest expense and loss on extinguishment of debt;

· Depreciation, depletion and amortization;

· Change in fair value of derivative contracts;

· Non-cash compensation expense; and

· Swap termination fees.

In calculating Estimated Adjusted EBITDA that we will need to pay cash distributions, we have included estimates of drilling capital expenditures for the twelve month period ending September 30, 2008. When calculating Estimated Adjusted EBITDA, we have included all of our operating subsidiaries.

Adjusted EBITDA is a significant performance metric used by our management to indicate (prior to the establishment of any reserves by our board of directors) the cash distributions we expect to pay our unitholders. Specifically, this financial measure indicates to investors whether or not we are generating operating cash flow at a level that can sustain or support an increase in our quarterly distribution rates. Adjusted EBITDA is also a quantitative standard used throughout the investment community with respect to publicly-traded partnerships and limited liability companies.

You should read the footnotes and assumptions and considerations detailed beneath the table under the caption “—Estimated Adjusted EBITDA” below for a discussion of the material assumptions underlying our belief that we will be able to generate the Estimated Adjusted EBITDA for the twelve months ending September 30, 2008. Our belief is based on these assumptions and reflects our judgment, as of the date of this prospectus, regarding the conditions we expect to exist and the course of action we expect to take over the twelve months ending September 30, 2008. The assumptions we disclose below are those that we believe are significant to our ability to generate the Estimated Adjusted EBITDA. If these estimates prove to be materially incorrect, we may not be able to pay the full initial quarterly distribution or any amount on our outstanding units for the twelve months ending September 30, 2008.

When considering our Estimated Adjusted EBITDA for the twelve months ending September 30, 2008, you should keep in mind the risk factors and other cautionary statements under the heading “Risk Factors.” Any of the risk factors discussed in this prospectus could cause our financial condition and results of operations to vary significantly from those set forth in the table below.

Estimated Adjusted EBITDA

The following table illustrates (i) our Estimated Adjusted EBITDA that we expect to generate for the twelve months ending September 30, 2008 based on the assumptions and considerations described in the footnotes to the table and in the assumptions and considerations described beneath the table and (ii) the estimated cash available to pay distributions for the twelve-month period ending September 30, 2008, assuming in each case that the offering was consummated on October 1, 2007. We explain each of the adjustments presented below in the footnotes to the table and in the assumptions and considerations described beneath the table. All of the amounts for the twelve-month period ending September 30, 2008 in the table, footnotes below and the assumptions and consideration described beneath the table below are estimates.

	Twelve Months Ending September 30, 2008 (without underwriters’ overallotment)				Twelve Months Ending September 30, 2008 (with underwriters’ overallotment)
	(in thousands, except per unit amounts)
Estimated Adjusted EBITDA(a)		$	35,732			$	35,732
Less:
Cash interest expense		(949		)		0
Maintenance capital expenditures(b)		(13,000		)		(13,000		)
Plus:
Borrowings		—				—
Estimated cash available to pay distributions		$	21,783			$	22,732
Estimated cash distributions:
Annualized initial quarterly distribution per unit		$	1.70			$	1.70
Distributions to public unitholders		$	8,500			$	9,775
Distributions to Private Investors		3,893				3,893
Distributions to Nami		5,525				5,525
Distributions to management(c)		782				782
Total estimated cash distributions		$	18,700			$	19,975
Excess		$	3,083			$	2,757
Interest coverage ratio(d)		38x				N/A
Ratio of total debt to Adjusted EBITDA(d)		0.41x				N/A

(a) As reflected in the table below, to generate our Estimated Adjusted EBITDA for the twelve months ending September 30, 2008, we have assumed the following regarding our operations, revenues and expenses:

	Twelve Months Ending September 30, 2008
Net Production:
Total production (MMcfe)		4,334
Average daily production (Mcfe/d)		11,875
Average Natural Gas Sales Price per MMBtu:
Average TECO Inside FERC Index sales price (swap hedged volumes)		$	9.00
Average NYMEX sales price (unhedged volumes)		$	8.00
Percent of total production hedged at assumed price levels		59		%
Weighted average net sales price per Mcfe		$	10.70
Estimated Adjusted EBITDA (in thousands):
Total revenue		$	46,395
Production costs		(7,163		)
Selling, general and administrative expenses		(3,500		)
Estimated Adjusted EBITDA		$	35,732

(b) For purposes of this table, we are assuming that we will fund all of our maintenance capital expenditures for the twelve months ending September 30, 2008 with cash flow from operations, while funding any acquisition capital expenditures that we might incur with borrowings under our reserve-based credit facility. We do not currently have any expected acquisition capital expenditures through the twelve-month period ending September 30, 2008, although that may change if acquisition opportunities become available to us in that period.

(c) Includes 240,000 Class B units issued to Scott W. Smith, our President and Chief Executive Officer, 125,000 Class B units issued to Richard A. Robert, our Executive Vice President and Chief Financial Officer, 50,000 Class B units issued to Britt Pence, our Vice President of Engineering, 5,000 Class B units issued to Patty Avila-Eady, our Financial Reporting Manager and the issuance of 40,000 common units to future employees and/or board members following the completion of this offering. The remaining 40,000 Class B units will be issued to additional management personnel that we intend to hire in the future.

(d) Our reserve-based credit facility contains covenants that, among other things, require us to maintain specified ratios or conditions as follows: (1) consolidated net income plus interest expense, income taxes, depreciation, depletion, amortization, changes in fair value of derivative instruments and other similar charges, minus all non-cash income added to consolidated net income, and giving pro forma effect to any acquisitions or capital expenditures, to interest expense of not less than 2.5 to 1.0; (2) consolidated current assets, including the unused amount of the total commitments, to consolidated current liabilities of not less than 1.0 to 1.0, excluding non-cash assets and liabilities under SFAS No. 133, which includes the current portion of derivative contracts; (3) consolidated debt to consolidated net income plus interest expense, income taxes, depreciation, depletion, amortization, changes in fair value of derivative instruments and other similar charges, minus all non-cash income added to consolidated net income, and giving pro forma effect to any acquisitions or capital expenditures of not more than 4.0 to 1.0 ; and (4) maintain unencumbered liquid assets of at least $2 million which includes unused availability under the borrowing base. We believe that we will be in compliance with

these covenants for the twelve-month period ending September 30, 2008. If an event of default exists under the reserve-based credit agreement, the lenders will be able to accelerate the maturity of the credit agreement and exercise other rights and remedies. Upon completion of this offering, we will have the ability to borrow under the reserve-based credit facility to pay distributions to unitholders as long as there has not been a default or event of default and if the amount of borrowings outstanding under our reserve-based credit facility is less than 50% of the borrowing base.

Assumptions and Considerations

Based upon the specific assumptions outlined below with respect to the twelve months ending September 30, 2008, we expect to generate cash flow from operations in an amount sufficient to fund our budgeted maintenance capital expenditures and pay the initial quarterly distribution on all units through September 30, 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 initial quarterly distribution (absent borrowings under our reserve-based credit facility), or any amount, on all units, in which event the market price of our 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 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. Decreases in commodity prices from current levels will adversely affect our ability to pay distributions. When reading this section, you should keep in mind the risk factors and other cautionary statements under the headings “Risk Factors,” and “Cautionary Note Regarding 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. Our net production pro forma for the year ended December 31, 2006 and the twelve months ended June 30, 2007 was 4,378 MMcfe and 4,349 Mcfe, respectively. We estimate that our total net production will remain relatively constant and will be approximately 4,334 MMcfe for the twelve months ending September 30, 2008. This relatively constant net production for the twelve months ending September 30, 2008 as compared to our pro forma twelve months ended June 30, 2007 is attributable to our expected participation through our approximate 40% working interest in the drilling of 195 gross (approximately 78 net) wells (or approximately 32.5 gross (approximately 13 net) wells per quarter) for the period commencing April 1, 2007 and ending September 30, 2008. During the six months ended June 30, 2007, we drilled 41 gross (16 net) wells. During 2007 and the nine months ending September 30, 2008, based on our historical experience, we expect that new wells will be producing and connected to a pipeline within 30 days after completion, which assumption includes an allowance for unexpected delays. We estimate that our average net daily production will be approximately 11,875 Mcfe for the twelve months ending September 30, 2008. On a pro forma basis, for the year ended December 31, 2006 and the twelve months ended June 30, 2007, our average net daily production was approximately 11,995 Mcfe and 11,914 Mcfe, respectively. Pursuant to our participation agreement with Vinland, Vinland generally has control over our drilling program and the sole right to determine which wells are drilled until January 5,

2011. During this period, we will meet with Vinland on a quarterly basis to review Vinland’s proposal to drill not less than 25 nor more than 40 gross wells, in which we will own an approximate 40% working interest, in any quarter. Up to 20% of the proposed wells may be carried over and added to the wells to be drilled in the subsequent quarter, provided that Vinland is required to drill at least 100 gross wells per calendar year. If Vinland proposes the drilling of less than 25 gross wells in any quarter, we have the right to propose the drilling of up to a total of 14 wells, in which we will own an approximate 100% working interest, in a given quarterly period. Based on our production rate at March 31, 2007 and June 30, 2007, we believe we need to drill approximately 130 gross (52 net) wells per year to maintain our production at current levels. By contrast, based upon a sensitivity analysis prepared by NSAI, if Vinland only drills its minimum commitment of 100 gross wells per calendar year, our total production is expected to decline by an average of approximately 2.7% per year for the three-year period beginning March 31, 2007. If Vinland drills its minimum commitment, we do not have the ability to drill our own additional wells in the AMI. If either party elects not to participate in the drilling of the proposed wells or future operations with respect to drilled wells, such party forfeits all right, title and interest in the natural gas and oil production that may be produced from such wells. Please read “Certain Relationships and Related Party Transactions.”

· Prices. We estimate that we will achieve a weighted average net sales price of approximately $10.70 per Mcfe for the twelve months ending September 30, 2008. The weighted average net sales price has been calculated as the sum of the forecasted sales revenues from all production plus any gains or losses from executed hedges divided by the sales volumes forecasted for the period. On a pro forma basis, for the twelve months ended December 31, 2006 and for the twelve months ended June 30, 2007, our average net realized sales price was approximately $8.22 per Mcfe and $8.35 per Mcfe, respectively. Our weighted average net sales price is calculated taking into account our unhedged production volumes (including our production volumes subject to put options at $7.50 per MMBtu) at an assumed price based on the NYMEX natural gas price of $8.00 per MMBtu (by comparison, the one-year forward NYMEX strip price as of September 4, 2007 was $7.65) and our executed swaps. For the twelve months ending September 30, 2008, approximately 60% of total production, or 2,549 MMcfe, is hedged using swap agreements at a weighted average TECO price of $9.00 per MMBtu and approximately 39% of our production, or 1,676 MMcfe, is subject to put options at $7.50 per MMBtu. Because we have assumed a natural gas price that is higher than the $7.50 per MMBtu price floor in our put options, our forecast period only includes the effect of our swap agreements. Our estimated weighted average natural gas sales price also includes an assumed premium of (a) $2.12 per Mcfe over average NYMEX sales prices per MMBtu on unhedged volumes, relating to our estimate of a positive Appalachian basis differential relative to the NYMEX price and positive Btu adjustments and (b) $2.07 per Mcfe over average TECO sales prices per MMBtu on swap hedged volumes relating to positive Btu adjustments. Pro forma for the year ended December 31, 2006 and for the twelve months ended June 30, 2007, we received an average positive adjustment of $1.97 per Mcfe and $1.65 per Mcfe, respectively, relating to a positive Appalachian basis differential relative to the NYMEX price and positive Btu adjustments. This is further adjusted for oil, which accounts for less than 2% of our production forecast and is assumed to have a net price of $58.00 per Bbl (by comparison, the one-year forward NYMEX strip price as of September 4, 2007 was $70.85), after a negative basis differential and transportation fees. We currently do not have any hedges in place with respect to our estimated oil production for the twelve months ending September 30, 2008. Please read “—Sensitivity Analysis.”

· Hedging. Pro forma for the year ended December 31, 2006 and for the twelve months ended June 30, 2007, we generated total gross revenue of $36.0 million and $36.3 million, respectively, excluding the non-cash change in fair value of derivative contracts. The estimated increase in gross revenues to $46.4 million for the twelve months ending September 30, 2008 is attributable

principally to increases in the average natural gas and oil sales prices. In addition, our gross revenues pro forma for the year ended December 31, 2006 and for the twelve months ended June 30, 2007 were reduced as a result of realized hedging losses of $2.2 million and $1.5 million, respectively. For the twelve months ending September 30, 2008, we estimate our gross revenues will be increased as a result of realized hedging gains of $2.4 million.

Expenses

· Production Costs. Production costs consist of the lease operating expenses, production taxes (severance and ad valorem taxes), overhead and administrative costs paid to Vinland, gathering and compression fees paid to Vinland, third-party transportation fees paid to Delta Natural Gas and Columbia Gas Transmission and other customary charges. Our forecasted lease operating expense (including gathering and compression costs) of $5.4 million compares to $5.1 million for the pro forma results for the year ended 2006 and for the pro forma results for the twelve months ended June 30, 2007. The increase in production costs is attributable to general cost escalation in the services provided and additional production during the forecast period being subject to a $0.55 per Mcfe gathering fee as opposed to a $0.25 per Mcfe gathering fee. Our production taxes are calculated as a percentage of our revenues, excluding the impact of hedges. As prices or volumes increase, our production taxes increase, or vice versa. Our forecasted average production tax rate of 4.4% is consistent with the production tax rate of 4.5% in Kentucky and 3% in Tennessee in 2006.

· Selling, General and Administrative Expenses. We estimate that our selling, general and administrative expenses for the twelve months ending September 30, 2008 will be approximately $3.5 million, excluding the impact of non-cash unit based compensation charges for the 420,000 Class B units granted to management prior to the completion of this offering, the 40,000 common units to be issued to future employees and/or directors following the completion of this offering, 175,000 options to be granted to management at the time of our initial public offering under our Long-Term Incentive Plan and phantom units to be granted to management commencing in 2008. Pro forma for the year ended December 31, 2006 and for the twelve months ended June 30, 2007, our selling, general and administrative expenses, excluding the impact of non-cash unit based compensation charges for the 420,000 Class B units granted to management prior to the completion of this offering the 40,000 common units to be issued to future employees and/or directors following the completion of this offering, 175,000 options to be granted to management at the time of our initial public offering under our Long-Term Incentive Plan and phantom units to be granted to management commencing in 2008, were $4.9 million and $5.6 million, respectively, which are higher than our anticipated selling, general and administrative expenses, principally due to a one-time non-recurring litigation settlement of $1.2 million and $1.4 million in associated legal fees paid in 2006 by our predecessor. Selling, general and administrative expenses are based on our estimate of the costs of our employees and executive officers, related benefits, office leases, professional fees, other costs not directly associated with field operations and the additional costs associated with being a public company. Should actual expenses be higher, we believe that we will have sufficient capacity under our reserve-based credit facility. Future employee bonuses and unit-based compensation may adversely impact our cash available for distribution.

· Interest Expense. Pro forma for the year ended December 31, 2006 and for the twelve months ended June 30, 2007, we had no interest expense and $0.7 million of interest expense, respectively. We anticipate that after giving effect to the application of net proceeds from this offering to pay $7.3 million of outstanding deferred swap liabilities and $94.4 million of the debt outstanding under our reserve-based credit facility, there will be an outstanding balance of $13.4 million on our reserve-based credit facility based on the debt outstanding at June 30, 2007. We estimate that this balance will bear an average variable interest rate of 6.5% for the twelve months ended

September 30, 2008 and our interest expense for this period will be $0.9 million. An increase or decrease of 1% in the interest rate will result in increased or decreased, respectively, annual interest expense of $0.1 million. If the underwriters exercise in full their option to purchase additional units, we will repay the remaining outstanding borrowings under our reserve-based credit facility, and we will have approximately $1.4 million to fund future working capital.

· Giving effect to the application of the net proceeds from this offering, our borrowing capacity is expected to be approximately $99.1 million under our reserve-based credit facility, assuming the current borrowing base of $112.5 million. We also anticipate that we will refinance any future outstanding debt when it becomes due. We estimate that we will have sufficient capacity under our reserve-based credit facility for the twelve months ending September 30, 2008 to, if necessary, fund capital expenditures and distributions. However, the amount of borrowing base and thus our ability to borrow is subject to semi-annual redeterminations based on our reserves and could be reduced by our lenders in connection with any such redetermination. To the extent we fund additional drilling activities or other expansion capital expenditures with borrowings under our reserve-based credit facility, our interest expense may increase. Should actual expenses be higher, we believe that we will have sufficient capacity under our reserve-based credit facility to fund such higher expenditures. Our limited liability company agreement does not restrict us from borrowing to pay distributions on our common units. We may borrow funds under our reserve based credit facility as long as there has not been a default or event of default under our credit agreement and if the amount of borrowings outstanding under our credit facility is less than 50% of our borrowing base. Please read "Risk Factors—Risks Related to Our Business—Our reserve-based credit facility has substantial restrictions and financial covenants and we may have difficulty obtaining additional credit, which could adversely affect our operations and our ability to pay distributions to our unitholders.”

Capital Expenditures

· All of our maintenance capital expenditures forecasted for the twelve months ending September 30, 2008 are for the drilling of new wells. We estimate that our drilling capital expenditures for the twelve months ending September 30, 2008 will be approximately $13.0 million, based on our expectation of drilling 130 gross (52 net) wells during the year at an average cost of $250,000 per well with expected gross reserves of 167 MMcfe per well. We expect to finance these capital expenditures from cash flow from operations. These drilling capital expenditures are intended to maintain our current production level if Vinland drills the assumed 32.5 gross (13 net) wells per quarter. If Vinland drills its minimum 25 gross wells per quarter, our drilling capital expenditures will decrease by $3.0 million. For the year ended December 31, 2006, our predecessor’s drilling capital expenditures were approximately $23.3 million, based on drilling 100 gross and net wells during the year at an average cost of $233,000 per well. For the twelve months ended June 30, 2007, our predecessor’s drilling capital expenditures were approximately $20.7 million, based on drilling 91 gross (66 net) wells during the year at an average cost of $227,000 per well. The decrease in estimated capital expenditures for the twelve months ending September 30, 2008 compared to the year ended December 31, 2006 and the twelve months ended June 30, 2007 is attributable to the drilling of fewer net wells, a reduction in prior capital costs by Vinland which previously funded a portion of the hook-up of the wells that will now be treated as an expense and a reduction in capitalized internal costs.

In preparing the estimates above, we have assumed that there will be no material change in the following matters, and thus they will have no impact on our Estimated Adjusted EBITDA:

· There will not be any material expenditures related to new federal, state or local regulations or interpretations.

· There will not be any material change in the natural gas and oil industry or in market, regulatory and general economic conditions that would affect our cash flow.

· We will not undertake any extraordinary transactions that would materially affect our cash flow.

· There will be no material nonperformance or credit-related defaults by suppliers, customers or vendors.

While we believe that the assumptions we used in preparing the estimates set forth above are reasonable based upon management’s current expectations concerning future events, they are inherently uncertain and are subject to significant business, economic, regulatory and competitive risks and uncertainties, including those described in “Risk Factors,” that could cause actual results to differ materially from those we anticipate. If our assumptions are not realized, the actual available cash that we generate could be substantially less than the amount we currently estimate and could, therefore, be insufficient to permit us to pay the full initial quarterly distribution or any amount on all our outstanding common units in respect of the four calendar quarters ending September 30, 2008 or thereafter, in which event the market price of the common units may decline materially.

Sensitivity Analysis

Our ability to generate sufficient cash from our operations to pay distributions to our unitholders of not less than the initial quarterly distribution per unit for the twelve months ending September 30, 2008 is a function of two primary variables: production volumes and natural gas 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 initial quarterly distribution on our outstanding units.

Production volume changes

For purposes of our estimates set forth above, we have assumed that our net production totals approximately 4,334 MMcfe during the twelve months ending September 30, 2008. If our actual net production realized during such twelve-month period is 5% more (or 5% less) than such estimate (that is, if actual net realized production is 4,551 MMcfe or 4,118 MMcfe), we estimate that our estimated cash available to pay distributions would increase (decrease) by approximately $1.9 million, assuming no changes in other variables.

Natural gas price changes

For purposes of our estimates set forth above, we have assumed that our weighted average net realized natural gas sales price for our unhedged production volumes (including our production volumes subject to put options at $7.50 per MMBtu) is $8.00 per MMBtu. If the average realized natural gas sales price for our net production volumes were to increase by $1.00 per MMBtu, we estimate that our estimated cash available to pay distributions would increase by approximately $1.8 million to $23.6 million. If the average realized natural gas sales price for our net production volumes were to decrease by $1.00 per MMBtu, we estimate that our estimated cash available to pay distributions would decrease by approximately $0.8 million to $21.0 million. Both scenarios assume we maintain hedges of approximately 60% of total production, or 2,549 MMcfe, using swap agreements at a weighted average TECO Inside FERC Index price of $9.00 per MMBtu and approximately 39% of our production, or 1,676 MMcfe, using put options at $7.50 per MMBtu and no other changes in any other variables.

In order to address, in part, volatility in natural gas prices, we have implemented a commodity price risk management program that is intended to reduce the volatility in our revenues due to short-term changes in natural gas prices. Under that program, we have adopted a policy that contemplates hedging

the prices for approximately 80% to 95% of our expected production from proved producing reserves for a period of up to five years, as appropriate. In addition, we may purchase NYMEX put options on the balance of our production to provide us with a price floor on such volumes. Implementation of such policy will mitigate, but will not eliminate, our sensitivity to short-term changes in prevailing natural gas prices.

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

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 cash available to pay distributions to our unitholders, assuming that the offering and the related transactions had been consummated at the beginning of the period.

Based on the information presented in the table below, our pro forma cash available to pay distributions generated during 2006 would have been approximately $11.9 million. This amount would have been sufficient to pay approximately 64% of our $1.70 annualized quarterly distribution (or 59% giving effect to the underwriters’ overallotment option being exercised). Based on the information presented in the table below, our pro forma cash available to pay distributions generated during the twelve months ended June 30, 2007 would have been approximately $12.6 million. This amount will be sufficient to pay approximately 68% of our $1.70 annualized quarterly distribution (or 63% giving effect to the underwriters’ overallotment option being exercised). Pro forma cash available to pay distributions excludes any cash from working capital or other borrowings. As described in “How We Make Cash Distributions—Definition of Available Cash,” we can use borrowings under our reserve-based credit facility to pay distributions. Therefore, we would have had the discretionary authority to borrow funds under our reserve-based credit facility to make up some or all of this estimated shortfall. For purposes of the table below, however, we have assumed that we did not borrow any amounts to fund such estimated shortfall and that we paid out 100% of our pro forma cash available for distributions.

In the future, it is management’s intent to borrow to the extent prudent and necessary to fund any short-term shortfall in cash available for distribution. Under our reserve-based credit facility, we expect to be able to incur debt to pursue our business plan and to pay distributions to our unitholders. However, we are prohibited from making distributions to unitholders if the amount of borrowings outstanding under our reserve-based credit facility reaches or exceeds 50% of the borrowing base, which is estimated to be $56.3 million upon the closing of the offering, or if we are then in default under such facility. As reflected in our June 30, 2007 unaudited pro forma balance sheet, after giving effect to the use of proceeds from this offering, our pro forma outstanding debt is $14.6 million.

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 date 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 cash available to pay distributions 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.

	Pro Forma Year Ended December 31, 2006 (without underwriters’ overallotment)				Pro Forma Year Ended December 31, 2006 (with underwriters’ overallotment)				Pro Forma Twelve Months Ended June 30, 2007 (without underwriters’ overallotment)				Pro Forma Twelve Months Ended June 30, 2007 (with underwriters’ overallotment)
	(in thousands except per unit amounts)				(in thousands except per unit amounts)				(in thousands except per unit amounts)				(in thousands except per unit amounts)
Net income		$	30,163			$	30,163			$	13,565			$	14,077
Unrealized gain on natural gas derivatives		(17,748		)		(17,748		)		(6,324		)		(6,324		)
Non-cash compensation expense		4,013				4,013				4,013				4,013
Depreciation, depletion and amortization		7,927				7,927				8,553				8,553
Swap termination fees		—				—				777				777
Interest income		(40		)		(40		)		(50		)		(50		)
Interest expense and loss on extinguishment of debt		—				—				3,197				2,685
Adjusted EBITDA		$	24,315			$	24,315			$	23,731			$	23,731
Less:
Maintenance capital expenditures(a)		(9,326		)		(9,326		)		(10,544		)		(10,544		)
Net revenue attributable to conveyed operations(a)		(3,106		)		(3,106		)		(1,553		)		(1,553		)
Plus:
Borrowings		—				—				—				—
Non-cash bad debt expense(b)		—				—				1,008				1,008
Estimated cash available to pay distributions		$	11,883			$	11,883			$	12,642			$	12,642
Estimated cash distributions
Annualized initial quarterly distribution per unit		$	1.70			$	1.70			$	1.70			$	1.70
Distributions to Public Unitholders		$	8,500			$	9,775			$	8,500			$	9,775
Distributions to Private Investors		3,893				3,893				3,893				3,893
Distributions to Nami		5,525				5,525				5,525				5,525
Distributions to Management		782				782				782				782
Total estimated cash distributions		$	18,700			$	19,975			$	18,700			$	19,975
Shortfall		$	(6,817	)		$	(8,092	)		$	(6,058	)		$	(7,333	)

(a) In connection with the Nami Restructuring Plan, on April 18, 2007 but effective as of January 5, 2007, we retained 40% of our predecessor’s working interest in the known producing horizons in approximately 95,000 gross undeveloped acres surrounding or adjacent to our existing wells in southeast Kentucky and northeast Tennessee, including the 480 identified drilling locations as of

January 5, 2007. During the twelve months ended December 31, 2006 and the twelve months ended June 30, 2007, we drilled 100 gross and net wells and 91 gross (66 net) wells, respectively. If the Nami Restructuring Plan had been consummated as of January 1, 2006, wells drilled in the twelve months ended December 31, 2006 and the first six months of the twelve months ended June 30, 2007 would have been drilled only approximately 40% net to our interest. Accordingly, the maintenance capital expenditures presented above for the twelve months ended December 31, 2006 and the first six months of the twelve months ended June 30, 2007 only reflect 40% of our actual drilling expenditures, which were approximately $23.3 million and $11.0 million, respectively. Additionally, we have reduced our net revenues attributable to wells drilled in 2006 and in the first six months of the twelve months ended June 30, 2007 by an estimate of the amount that would have been earned by Vinland pursuant to their approximate 60% ownership interest in these wells if our predecessor’s 60% ownership interest in such wells was conveyed to Vinland as of January 5, 2006. Net revenue is defined as revenue less applicable lease operating expenses and taxes other than income incurred on the revenue.

(b) Reflects a provision for loss related to the entire amount receivable from an oil-buying customer which filed for protection under Chapter 11 of the Bankruptcy Code in May 2007.

HOW WE MAKE CASH DISTRIBUTIONS

Distributions of Available Cash

Our limited liability company agreement requires that, within 45 days after the end of each quarter, beginning with the quarter ending December 31, 2007, we distribute all of our available cash to unitholders of record on the applicable record date.

Definition of Available Cash

We define available cash in the glossary, and it generally means, for each fiscal quarter, all cash on hand at the end of the quarter:

· less the amount of cash reserves established by our board of directors to:

· provide for the proper conduct of our business (including reserves for acquisitions of additional oil and natural gas properties, future capital expenditures, future debt service requirements, and for our anticipated credit needs);

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

· provide funds for distribution to our unitholders for any one or more of the next four quarters;

· plus all cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter for which the determination is being made. Working capital borrowings are generally borrowings that will be made under our reserve-based credit facility and in all cases are used solely for working capital purposes or to pay distributions to unitholders.

Distributions of Cash Upon Liquidation

If we dissolve in accordance with the limited liability company 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, 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.

Adjustments to Capital Accounts

We will make adjustments to capital accounts upon the issuance of additional units. In doing so, we will allocate any unrealized and, for tax purposes, unrecognized gain or loss resulting from the adjustments to the unitholders in the same manner as we allocate gain or loss upon liquidation.

SELECTED HISTORICAL AND PRO FORMA CONSOLIDATED FINANCIAL DATA

Set forth below is selected historical and pro forma consolidated financial and operating data for the periods indicated for Vanguard Natural Resources, LLC and Vanguard Natural Gas, LLC, our predecessor. The historical financial data for the years ended December 31, 2004, 2005 and 2006 and the balance sheet data as of December 31, 2004, 2005 and 2006 have been derived from the audited financial statements of our predecessor. The historical financial data for the year ended December 31, 2002 and 2003 and the balance sheet data as of December 31, 2002 and December 31, 2003 are derived from the unaudited financial statements of our predecessor. The selected historical financial data for the six months ended June 30, 2006 and 2007 and the balance sheet data as of June 30, 2006 and 2007 have been derived from the unaudited financial statements of Vanguard Natural Resources, LLC or its predecessor. The pro forma as adjusted statement of operations data for the year ended December 31, 2006 gives effect to the following transactions as if such transactions occurred on January 1, 2006:

· the separation of our predecessor and Vinland as part of the Nami Restructuring Plan;

· the contribution of our predecessor to Vanguard Natural Resources, LLC

· our recent private placement;

· the granting of 420,000 Class B units to management and the granting of 40,000 common units to future employees and/or board members following the completion of this offering; and

· this offering.

· the granting of 420,000 Class B units to management and the granting of 40,000 common units to future employees and/or board members following the completion of this offering; and

· this offering.

You should read the following selected financial data in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our financial statements and related notes appearing elsewhere in this prospectus. You should also read the pro forma information together with the Unaudited Pro Forma Financial Statements and related notes included in this prospectus.

	Predecessor															Vanguard			Pro Forma As Adjusted
													Six Months			Six Months						Six Months
	Year Ended December 31,												Ended June 30,			Ended June 30,			Year Ended December 31,			Ended June 30,
	2002			2003			2004		2005		2006		2006			2007			2006			2007
	unaudited			unaudited									(unaudited)			(unaudited)			(unaudited)			(unaudited)
													(in thousands)
Statement of Operations Data:
Revenues:
Natural gas and oil sales		$ 9,313			$ 17,844		$ 23,881		$ 40,299		$ 38,184			$ 19,416			$ 19,068			$ 38,185			$ 19,068
Realized losses on derivative contracts		—			(1,939	)	(5,926	)	(10,024	)	(2,208	)		(2,341	)		(1,666	)		(2,208	)		(1,666	)
Change in fair value of derivative contracts(1)		—			—		(991	)	(18,779	)	17,748			11,424			—			17,748			—
Other		1,778			83		29		451		665			—			—			—			—
Total revenues		11,091			15,988		16,993		11,947		54,389			28,499			17,402			53,725			17,402
Costs and Expenses:
Lease operating expenses		844			2,126		2,407		4,607		4,896			2,375			2,460			5,068			2,460
Depreciation, depletion and amortization		2,505			3,109		4,029		6,189		8,633			4,047			4,320			7,927			4.320
Selling, general and administrative		3,172			3,454		3,154		5,946		5,199			960			1,215			8,876			3,584
Bad debt expense		—			—		—		—		—			—			1,008			—			1,008
Taxes other than income		302			505		611		1,249		1,774			651			891			1,731			891
Total costs and expenses		6,823			9,194		10,201		17,991		20,502			8,033			9,894			23,602			12,263
Income (Loss) from Operations:		4,268			6,794		6,792		(6,044	)	33,887			20,466			7,508			30,123			5,139
Other Income and (Expenses):
Interest income		6			14		7		52		40			18			28			40			28
Interest and financing expenses		(1,506	)		(1,413	)	(1,455	)	(4,566	)	(7,372	)		(3,784	)		(4,420	)		—			(695	)
Loss on extinguishment of debt		—			—		—		—		—			—			(2,502	)		—			(2,502	)
Total other income and (expenses)		(1,500	)		(1,399	)	(1,448	)	(4,514	)	(7,332	)		(3,766	)		(6,894	)		40			(3,169	)
Net income (loss)		$ 2,768			$ 5,395		$ ��5,344		$ (10,558	)	$ 26,555			$ 16,700			$ 614			$ 30,163			$ 1,970
Cash Flow Data:
Net cash provided by/(used in) operating activities(1)		6,997			$ 7,058		$ 9,607		$ 10,530		$ 16,087			$ 7,229			$ (2,833	)		$ —			$ —
Net cash used in investing activities		(7,613	)		(10,641	)	(19,598	)	(37,068	)	(37,383	)		(14,326	)		(6,620	)		—			—
Net cash provided by financing activities		5,699			(500	)	12,721		25,571		19,985			5,196			12,167			—			—
Other Financial Information (unaudited):
Adjusted EBITDA(2)		$ 6,773			$ 9,903		$ 11,812		$ 18,924		$ 24,772			$ 13,089			$ 13,167			$ 24,315			$ 12,243

	Predecessor									Vanguard			Pro Forma As Adjusted
	As of December 31,							As of June 30,		As of June 30,			As of June 30,
	2002		2003		2004	2005	2006	2006		2007			2007
	(unaudited)		(unaudited)					(unaudited)		(unaudited)			(unaudited)
								(in thousands)
Balance Sheet Data:
Cash and cash equivalents		$ 5,362		$ 1,279	$ 4,009	$ 3,041	$ 1,731		$ 1,141		$ 4,445			$ 4,445
Other current assets		3,778		6,473	10,033	19,598	20,438		22,075		9,130			7,558
Natural gas and oil properties, net of accumulated depreciation, depletion and amortization		32,766		39,555	54,761	83,513	104,684		89,789		101,611			101,611
Property, plant and equipment, net of accumulated depreciation		659		1,480	1,894	4,104	11,873		8,206		31			31
Other assets		—		—	—	—	—		—		4,785			4,785
Total assets		$ 42,565		$ 48,787	$ 70,697	$ 110,256	$ 138,726		$ 121,211		$ 120,002			$ 118,430
Short-term derivative liabilities		$ —		$ —	$ 800	$ 11,527	$ 2,022		5,395		—			—
Other current liabilities		2,297		3,545	6,347	12,033	11,505		13,532		12,581			5,258
Long-term debt		26,817		28,318	42,318	72,708	94,068		78,707		109,000			14,623
Long-term derivative liabilities		—		—	191	8,243	—		2,951		4,049			4,049
Other long-term liabilities		—		78	130	212	418		313		435			435
Members’ capital/(deficit)		13,451		16,846	20,911	5,533	30,713		20,313		(6,063	)		94,065
Total liabilities and members’ capital		$ 42,565		$ 48,787	$ 70,697	$ 110,256	$ 138,726		$ 121,211		$ 120,002			$ 118,430

(2) See “Prospectus Summary—Non-GAAP Financial Measure.”

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 Unaudited Pro Forma Consolidated Financial 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 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 “Cautionary Note Regarding 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 an independent natural gas and oil company focused on the acquisition, development and exploitation of mature, long-lived natural gas and oil properties. Our primary business objective is to generate stable cash flows allowing us to make quarterly cash distributions to our unitholders and over time to increase our quarterly cash distributions. Our properties are located in the southern portion of the Appalachian Basin, primarily in southeast Kentucky and northeast Tennessee. Please read “Business—Description of Our Properties.”

We owned working interests in 891 gross (805 net) productive wells at June 30, 2007 and our average net production for the twelve months ended December 31, 2006 and for the six months ended June 30, 2006 was 11,995 Mcfe per day and 11,925 Mcfe per day, respectively. We also have 40% of our predecessor’s working interest in the known producing horizons in approximately 95,000 gross undeveloped acres surrounding or adjacent to our existing wells located in southeast Kentucky and northeast Tennessee. In the separation, Vinland was conveyed the remaining 60% of our predecessor’s working interest in the known producing horizons in this acreage and 100% of our predecessor’s working interest in depths above and 100 feet below our known producing horizons. Vinland acts as the operator of our existing wells and all of the wells that we will drill in this area. Approximately 25%, or 16.3 Bcfe, of our pro forma estimated proved reserves as of December 31, 2006 were attributable to the 40% of our predecessor’s working interest. In addition, we own a contract right to receive approximately 99% of the net proceeds, after deducting royalties paid to other parties, severance taxes, third-party transportation costs, costs incurred in the operation of wells and overhead costs, from the sale of production from oil and gas wells, which accounted for approximately 5% of our pro forma estimated proved reserves as of December 31, 2006. Our estimated pro forma proved reserves at March 31, 2007 were 66.7 Bcfe, of which approximately 98% were natural gas and 75% were classified as proved developed. Our properties, including our working interest in the known producing horizons in approximately 95,000 gross undeveloped acres, fall within an approximate 750,000 acre area, which we refer to in this prospectus as the “area of mutual interest,” or AMI. We have agreed with Vinland until January 1, 2012 to offer the other the right to participate in any acquisition, exploitation and development opportunities that arise in the AMI, subject however to Vinland’s right to consummate up to two acquisitions with a purchase price of $5 million or less annually without a requirement to offer us the right to participate in such acquisitions.

months ended June 30, 2007. As reflected in the reserve report, as of March 31, 2007, we had identified 338 proved undeveloped drilling locations and over 171 other drilling locations on our leasehold acreage. Pursuant to our participation agreement with Vinland, Vinland generally has control over our drilling program and the sole right to determine which wells are drilled until January 5, 2011. During this period, we will meet with Vinland on a quarterly basis to review Vinland’s proposal to drill not less than 25 nor more than 40 gross wells, in which we will own an approximate 40% working interest, in any quarter. Up to 20% of the proposed wells may be carried over and added to the wells to be drilled in the subsequent quarter, provided that Vinland is required to drill at least 100 gross (approximately 40 net) wells per calendar year. If Vinland proposes the drilling of less than 25 gross wells in any quarter, we have the right to propose the drilling of up to a total of 14 wells, in which we will own an approximate 100% working interest, in a given quarterly period. Based on our production rate at March 31, 2007 and June 30, 2007, we believe we need to drill approximately 130 gross (52 net) wells per year to maintain our production at current levels. By contrast, based upon a sensitivity analysis prepared by NSAI, if Vinland only drills its minimum commitment of 100 gross wells per calendar year, our total production is expected to decline by an average of approximately 2.7% per year for the three-year period beginning March 31, 2007. If Vinland drills its minimum commitment, we do not have the ability to drill our own additional wells in the AMI. If either party elects not to participate in the drilling of the proposed wells or future operations with respect to drilled wells, such party forfeits all right, title and interest in the natural gas and oil production that may be produced from such wells. The participation agreement will remain in place until January 5, 2012 and shall continue thereafter on a year to year basis until such time as either party elects to terminate the agreement. The obligations of the parties with respect to the drilling program described above will expire on January 5, 2011, after which we each will have the right to propose the drilling of wells within the AMI and thereby offer participation in such proposed drilling to the other party and if either party elects not to participate in such proposed drilling or future operations with respect to drilled wells, such party forfeits all right, title and interest in the natural gas and oil production that may be produced from such wells. Please read “Certain Relationships and Related Party Transactions.”

On April 18, 2007 but effective as of January 5, 2007, we entered into various agreements with Vinland, under which we will rely on Vinland to operate our existing producing wells and coordinate our development drilling program. We expect to benefit from the substantial development and operational expertise of Vinland management in the Appalachian Basin. Under a management services agreement, Vinland advises and consults with us regarding all aspects of our production and development operations and provides us with administrative support services as necessary for the operation of our business. In addition, Vinland may, but does not have any obligation to, provide us with acquisition services under the management services agreement. While Vinland is not obligated to provide us with acquisition services, we expect that Nami’s significant equity interest in us will provide Vinland with an incentive to grow our business by helping us to identify, evaluate and complete acquisitions that will be accretive to our distributable cash. In addition, under a gathering and compression agreement that we entered into with Vinland, Vinland will gather, compress, deliver and provide the services necessary for us to market our natural gas production in the area of mutual interest. Vinland will deliver our natural gas production to certain designated interconnects with third-party transporters. Since the various agreements were executed on April 18, 2007 but were effective as of January 5, 2007, Vinland reimbursed us for the drilling costs and expenses that we incurred on their behalf associated with their interest in the wells drilled between January 5, 2007 and April 18, 2007. In addition, Vinland reimbursed us for selling, general and administrative expenses that we incurred on their behalf between January 5, 2007 and April 18, 2007. We reimbursed Vinland for certain transaction costs and expenses relating to entering into these agreements. Please read “Certain Relationships and Related Party Transactions.”

Nami Restructuring Plan

Prior to the separation, our predecessor owned all of the assets that are currently owned by us and Vinland. As part of the separation of our operating company and Vinland, effective January 5, 2007, we conveyed to Vinland 60% of our predecessor’s working interest in the known producing horizons in approximately 95,000 gross undeveloped acres in the AMI, 100% of our predecessor’s interest in an additional 125,000 undeveloped acres and certain coalbed methane rights located in the Appalachian Basin, the rights to any natural gas and oil located on our acreage at depths above and 100 feet below our known producing horizons, all of our gathering and compression assets and all employees other than our President and Chief Executive Officer and our Executive Vice President and Chief Financial Officer. We retained all of our predecessor’s proved producing wells and associated reserves. We also retained 40% of our predecessor’s working interest in the known producing horizons in approximately 95,000 gross undeveloped acres in the AMI and a contract right to receive approximately 99% of the net proceeds, after deducting royalties paid to other parties, severance taxes, third-party transportation costs, costs incurred in the operation of wells and overhead costs, from the sale of production from certain producing oil and gas wells, which accounted for approximately 5% of our pro forma estimated proved reserves as of March 31, 2007. In addition, we recently changed the name of our operating company from Nami Holding Company, LLC to Vanguard Natural Gas, LLC.

Private Offering

In April 2007, we completed a private equity offering pursuant to which we issued 2,290,000 units to certain private investors, including an affiliate of Lehman Brothers Inc., which we collectively refer to as the Private Investors, for $41.2 million. We used the net proceeds of this private equity offering to make a distribution to Nami, who used a portion of these funds to capitalize Vinland and also paid us $3.9 million to reduce outstanding accounts receivable from Vinland. We then used the $3.9 million to repay borrowings and interest under our reserve-based credit facility, and for general limited liability company purposes. Under the terms of the private offering, all outstanding units accrue distributions at $1.70 annually from the closing of the private offering to the completion of the initial public offering at which time all accrued distributions will be paid.

Reserve-Based Credit Facility

On January 3, 2007, our operating company entered into a reserve-based credit facility. Our initial borrowing base under the reserve-based credit facility was set at $115.5 million, of which $109.0 million was outstanding as of June 30, 2007. As of September 1, 2007, our borrowing base was reduced to $112.5 million, of which $107.8 million was outstanding as of that date. The borrowing base of our reserve-based credit facility is subject to $1 million reductions per month until our next borrowing base redetermination date of October 1, 2007. The reserve-based credit facility is available for our general limited liability company purposes, including, without limitation, capital expenditures and acquisitions. Our obligations under the reserve-based credit facility are secured by substantially all of our assets. We intend to use a portion of the net proceeds from this offering to partially repay the indebtedness outstanding under the reserve-based credit facility.

Outlook

Our revenue, cash flow from operations and future growth depend substantially on factors beyond our control, such as economic, political and regulatory developments and competition from other sources of energy. Natural gas and oil prices historically have been volatile and may fluctuate widely in the future. Sustained periods of low prices for natural gas or oil could materially and adversely affect our financial position, our results of operations, the quantities of natural gas and oil reserves that we can economically produce and our access to capital. As required by our reserve-based credit facility, we have mitigated this

volatility for the years 2007 through 2011 by implementing a hedging program on our proved producing and total anticipated production during this time frame.

We face the challenge of natural gas production declines. As a given well’s initial reservoir pressures are depleted, natural gas production decreases, thus reducing our total natural gas reserves. We attempt to overcome this natural decline both by drilling on our properties and acquiring additional reserves. We will maintain our focus on controlling costs to add reserves through drilling and acquisitions, as well as controlling the corresponding costs necessary to produce such reserves. Our ability to add reserves through drilling is dependent on our capital resources and can be limited by many factors, including the ability of Vinland to timely obtain drilling permits and regulatory approvals. Any delays in drilling, completion or connection to gathering lines of our new wells will negatively impact the rate of our production, which may have an adverse effect on our revenues and as a result, cash available for distribution. In accordance with our business plan, we intend to invest the capital necessary to maintain our production or operating capacity and our asset base over the long-term.

We utilize the full cost method of accounting for our natural gas and oil properties. Under the full cost method, substantially all costs incurred in connection with the acquisition, development and exploration of natural gas and oil reserves are capitalized. These capitalized amounts include the costs of unproved properties, internal costs directly related to acquisition, development and exploration activities, asset retirement costs and capitalized interest. Under the full cost method, both dry hole costs and geological and geophysical costs are capitalized into the full cost pool, which is subject to amortization and subject to ceiling test limitations.

We expect that, during 2007 and for the remainder of our forecast period, our business will continue to be affected by the risks described in “Risk Factors,” as well as the following key industry and economic trends. Our expectation is based upon key assumptions and information currently available to us. To the extent that our underlying assumptions about or interpretations of available information prove to be incorrect, our actual results may vary materially from our expected results.

Production and Drilling. Our net production for 2006 was approximately 4,378 MMcfe. As reflected in the reserve report, as of March 31, 2007, we had identified 338 proved undeveloped drilling locations and over 171 other drilling locations on our leasehold acreage. Based on our existing identified drilling locations and assuming we drill approximately 130 of our identified drilling locations per year, we believe we will be able to maintain our current total production for approximately four years from March 31, 2007, the date of the reserve report. We have entered into a participation agreement with Vinland wherein we will meet with Vinland on a quarterly basis to review the proposed drilling of not less than 25 nor more than 40 gross wells, in which we will own an approximate 40% working interest, in any quarter ending before January 5, 2011. For the twelve months ending September 30, 2008, we expect net production of approximately 4,334 MMcfe. This is based upon our current drilling plans, which includes a total of 130 gross (52 net) newly drilled wells during that twelve-month period.

Natural Gas Prices. Natural gas prices have been extremely volatile over the past three years and even more so in the past twelve months. We believe that this trend has been significantly affected by the lack of hurricanes in the summer and fall of 2006, threats and existence of wars and terrorism in the Middle East and Africa and elsewhere, OPEC’s management of oil reserves (given the correlation between natural gas and oil) and growth in domestic natural gas demand. The currently high levels of natural gas in storage, resulting at least in part from relatively mild winters in 2005 and 2006 in the United States, have caused natural gas prices to decline from the higher levels prevailing during the later part of 2005.

Hedging Activities. We enter into hedging arrangements to reduce the impact of natural gas price volatility on our cash flow from operations. Currently, we use a combination of fixed-price TECO swaps and NYMEX put options to hedge natural gas prices. Our fixed-priced swaps in place from July 1, 2007 through 2011 hedge approximately 80% of our expected production from wells producing at

March 31, 2007 at a weighted average price of $8.33 per MMBtu. However, as a result of expected production from wells that began or are expected to begin producing after March 31, 2007, our fixed-price TECO swaps hedge approximately 60% of our total production for the twelve month period ending September 30, 2008 at $9.00 per MMBtu. In addition, we also have purchased NYMEX put options with a floor of $7.50 per MMBtu covering a substantial portion of our remaining total expected gas production through 2009. We expect our hedging policy will be to hedge approximately 80% to 95% of our total forecasted production for a three year period using a combination of fixed-price TECO swap contracts and NYMEX put options. Our board of directors may modify the hedging percentages and strategies as it deems appropriate for market conditions and our business strategy.

Production Costs. Our production costs include such items as lease operating expenses, production taxes (severance and ad valorem taxes), overhead and administrative costs paid to Vinland as well as gathering and compression fees and other customary charges. Due to the current environment of relatively high commodity prices, we anticipate that, service and labor costs, as well as costs of equipment and raw materials, will remain at or exceed the levels we experienced in 2005 and 2006. The management services agreement and the gathering and compression agreement described above that we entered into with Vinland will fix a portion of our production costs for wells owned in the AMI. There are additional expenses paid to third parties, and we expect that this portion of our future production costs will be correlated to the price of natural gas, although the cost changes generally lag price changes in, and are less volatile than, natural gas. When natural gas prices are higher, demand for these services is higher, resulting in increased costs for such services and vice versa. Our production taxes are directly correlated to our revenues, as they are calculated as a percentage of sales revenue after certain deductions.

Selling, General and Administrative Expenses. We expect that our selling, general and administrative expenses, excluding the impact of non-cash unit based compensation charges for the 420,000 Class B units granted to management prior to the completion of this offering, the 40,000 common units to be issued to future employees and/or directors following the completion of this offering, 175,000 options to be granted to management at the completion of this offering under our Long-Term Incentive Plan and phantom units to be granted to management commencing in 2008, will be approximately $3.5 million for the twelve months ending September 30, 2008. There are three main components of these estimated costs:

· salaries and benefits of our employees, office rent, travel costs and other similar administrative expenses that will comprise approximately $1.1 million of our forecasted selling, general and administrative costs;

· costs associated with being a public company, including annual and quarterly reports to unitholders, our annual meeting of unitholders, tax return and Schedule K-1 preparation and distribution, investor relations, registrar and transfer agent fees, incremental insurance costs, fees of independent directors, accounting fees and legal fees that will comprise approximately $1.9 million of our estimated total selling, general and administrative expenses;

· other overhead charges, including third-party consulting fees that will comprise approximately $0.5 million of our estimated total selling, general and administrative expenses.

The estimated costs above assume that we do not make any acquisitions during the twelve-month period ending September 30, 2008, and that we do not reimburse Vinland under the management services agreement for any acquisition services during such period.

Comparability of Financial Statements

The historical financial statements of our predecessor included in this prospectus may not be comparable to our results of operations following this offering for the following reasons:

· We conveyed to Vinland 60% of our predecessor’s working interest in the known producing horizons in approximately 95,000 gross undeveloped acres in the AMI, 100% of our predecessor’s

interest in an additional 125,000 undeveloped acres and certain coalbed methane rights located in the Appalachian Basin, the rights to any natural gas and oil located on our acreage at depths above and 100 feet below our known producing horizons and all of our gathering and compression assets. In addition, all of the employees except our President and Chief Executive Officer and Executive Vice-President and Chief Financial Officer were transferred to Vinland.

· We entered into a management services agreement and a gathering and compression agreement with Vinland which will fix a portion of our production costs for wells owned in the AMI.

· Our predecessor did not account for its derivative instruments as cash flow hedges under SFAS No. 133 until the first quarter of 2007. Accordingly, the changes in the fair value of its derivative instruments are currently reflected in earnings for all periods prior to 2007 and in Other Comprehensive Income for the six months ended June 30, 2007.

· We will incur additional selling, general and administrative expense estimated to be $1.9 million per year for costs associated with being a public company. Also, we will incur non-cash compensation charges for the 420,000 Class B units granted to management prior to the completion of the offering, the 40,000 common units to be issued to future employees and/or directors following the completion of this offering, 175,000 options to be granted to management at the completion of this offering under our Long-Term Incentive Plan and phantom units to be granted to management commencing in 2008.

Results of Operations

The following table sets forth selected financial and operating data for the periods indicated.

	Year Ended December 31,									Six Months Ended June 30,
	2006			2005			2004			2007			2006
	(in thousands)									(unaudited)
Revenues:
Natural gas and oil sales	$	38,184		$	40,299		$	23,881		$	19,068		$	19,416
Realized losses on derivative contracts	(2,208		)	(10,024		)	(5,926		)	(1,666		)	(2,341		)
Change in fair value of derivative contracts	17,748			(18,779		)	(991		)	—			11,424
Other	665			451			29			—			—
Total revenues	$	54,389		$	11,947		$	16,993		$	17,402		$	28,499
Costs and expenses:
Lease operating expenses	$	4,896		$	4,607		$	2,407		2,460			2,375
Depreciation, depletion and amortization	8,633			6,189			4,029			4,320			4,047
Selling, general and administrative expenses	5,199			5,946			3,154			1,215			960
Bad debt expense	—			—			—			1,008			—
Taxes other than income	1,774			1,249			611			891			651
Total costs and expenses	$	20,502		$	17,991		$	10,201		$	9,894		$	8,033
Other Income and (Expenses):
Interest expense, net	$	(7,332	)	$	(4,514	)	$	(1,448	)	$	(4,392	)	$	(3,766	)
Loss on extinguishment of debt	$	—		$	—		$	—		$	(2,502	)	$	—

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

Revenues

Natural gas and oil sales decreased $0.3 million to $19.1 million during the six months ended June 30, 2007 as compared to the six months ended June 30, 2006. The key revenue measurements were as follows:

	Six Months Ended June 30,				Percentage Increase
	2007		2006		(Decrease)
Net Production:
Total Production (MMcfe)	2,158		2,188			(1	)%
Average Daily production (Mcfe/d)	11,925		12,087			(1	)%
Average Sales Price per Mcfe:
Average sales price (including hedges)	$	8.06	$	7.80		3	%
Average sales price (excluding hedges)	$	8.83	$	8.87		0	%

The small decrease in natural gas and oil sales was due primarily to the 1% decrease in production for the six months ended June 30, 2007 over June 30, 2006.

Hedging Activities

During the six months ended June 30, 2007, we hedged approximately 77% of our natural gas production, which resulted in revenues that were $0.9 million less than we would have achieved at unhedged prices. In addition, in January 2007, we terminated existing natural gas swaps at a cost of approximately $2.8 million which resulted in an additional realized loss on derivative contracts of approximately $0.8 million during the six months ended June 30, 2007. During the six months ended June 30, 2006, we hedged approximately 54% of our natural gas production, which resulted in revenues that were $2.3 million less than we would have achieved at unhedged prices. The derivative contracts entered into in 2006 and 2005 were not specifically designated as hedges under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities and therefore did not qualify for hedge accounting treatment. As a result, the change in the fair value of these natural gas derivative contracts are marked to market in our earnings each period and resulted in an $11.4 million non-cash gain for the six months ended June 30, 2006.

Costs and Expenses

Production costs consist of lease operating expenses and production taxes (severance and ad valorem taxes). Lease operating expenses includes third-party transportation costs, operating and maintenance costs associated with our gathering systems (which were conveyed to Vinland in connection with the Nami Restructuring Plan) and other customary charges. As a result of the Nami Restructuring Plan, for the six months ended June 30, 2007, lease operating expenses includes third-party transportation costs, a $60 per month per well administrative charge pursuant to our management services agreement with Vinland, a $0.25 per Mcf and $0.55 per Mcf gathering and compression charge for production from wells drilled pre and post January 1, 2007, respectively, paid to Vinland pursuant to a gathering and compression agreement with Vinland, as well as other customary charges. Lease operating expenses increased $0.1 million to $2.5 million for the six months ended June 30, 2007, as compared to $2.4 million for the six months ended June 30, 2006 due primarily to the amounts paid to Vinland under the management services agreement and gathering and compression agreement being comparable to our actual costs incurred for the same period in 2006. On a per Mcfe basis, lease operating expenses increased 5% to $1.14 for the six months ended June 30, 2007, as compared to $1.09 for the same period in 2006. Production taxes are a function of volumes and revenues generated from production. Ad valorem taxes vary by state and county and are based on the value of our reserves. Production taxes increased $0.2 million to $0.9 million, or 37% on a per

Mcfe basis, for the six months ended June 30, 2007, as compared to the six months ended June 30, 2006. This increase was principally due to a $0.2 million underaccrual of production taxes in 2006, which were charged to expense in the first quarter of 2007.

	Six Months Ended June 30,						Percentage Increase
	2007			2006			(Decrease)
Lease operating expenses per Mcfe		$	1.14		$	1.09		5	%
Production taxes per Mcfe		$	0.41		$	0.30		37	%

Depreciation, depletion and amortization increased $0.3 million to $4.3 million for the six months ended June 30, 2007 despite the conveyance of certain assets to Vinland pursuant to the Nami Restructuring Plan effective in January 2007. This result occurred due to the conveyance of long-lived depreciable assets which generated little associated depreciation and the conveyed value of the 60% interest in proved undeveloped properties was largely offset by the value of new wells drilled since June 30, 2006. In addition, the small increase in depletion can be attributed to upward revisions of future drilling costs which increases the full cost pool at June 30, 2007.

Selling, general and administrative expenses include the costs of our employees and executive officers, related benefits, office leases, professional fees and other costs not directly associated with field operations. These expenses for the six months ended June 30, 2007 include the impact of the Nami Restructuring Plan which transferred all of the employees other than two of its officers to Vinland. Selling, general and administrative expenses increased $0.2 million to $1.2 million for the six months ended June 30, 2007 as compared to $1.0 million for the six months ended June 30, 2006. The increase resulted from two principal factors. First, our predecessor capitalized $2.2 million of internal costs under the full-cost method of accounting for natural gas and oil properties for the six months ended June 30, 2006 whereas we have not capitalized any internal costs in 2007. Second, the six months ended June 30, 2007 includes a $0.6 million non-cash compensation charge related to the grant of Class B units to management in April 2007. Excluding the impact of the approximate $0.6 million non-cash unit compensation charge discussed above, selling, general and administrative expenses would have been $0.6 million for the six months ended June 30, 2007.

Bad debt expense of approximately $1.0 million was recorded during the six months ended June 30, 2007 as a result of a provision for a loss on the entire amount due from a customer which filed for protection under Chapter 11 of the Bankruptcy Code in May 2007. The account receivable was due from oil sales through December 2006 at which time we ceased selling oil to the customer. As the amount of any potential recovery is uncertain, we elected to reserve the entire balance. We began selling our oil production to a new customer beginning in March 2007.

Interest and financing expenses were approximately $4.4 million for the six months ended June 30, 2007 compared to approximately $3.8 million for the six months ended June 30, 2006. The increase in 2007 is primarily due to increased debt levels associated with drilling additional wells and rising interest rates.

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

Revenues

Natural gas and oil sales decreased $2.1 million to $38.2 million during the year ended December 31, 2006 as compared to the year ended December 31, 2005. The key revenue measurements were as follows:

	Year Ended December 31,				Percentage Increase
	2006		2005		(Decrease)
Net Production:
Total Production (MMcfe)	4,378		3,894			12	%
Average Daily production (Mcfe/d)	11,995		10,669			12	%
Average Sales Price per Mcfe:
Average sales price (including hedges)	$	8.22	$	7.77		6	%
Average sales price (excluding hedges)	$	8.72	$	10.35		(16	)%

The decrease in natural gas and oil sales was due primarily to the 16% decrease in the average sales price received (excluding hedges). This was mitigated by a 12% increase in the production for the year ended December 31, 2006 over 2005 due to the drilling of 100 wells during the year ended 2006.

Hedging Activities

During the year ended December 31, 2006, we hedged approximately 53% of our natural gas production, which resulted in revenues that were $2.2 million less than we would have achieved at unhedged prices. During the year ended December 31, 2005, we hedged approximately 68% of our natural gas production, which resulted in revenues that were $10.0 million less then we would have achieved at unhedged prices. The derivative contracts entered into in 2006 and 2005 were not specifically designated as hedges under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities and therefore did not qualify for hedge accounting treatment. As a result, the change in the fair value of these natural gas derivative contracts are marked to market in our earnings each period and resulted in $17.7 million in non-cash gain and $18.8 million in non-cash loss in 2006 and 2005, respectively.

Costs and Expenses

Production costs consist of the lease operating expenses and production taxes (severance and ad valorem taxes). Lease operating expenses includes gathering and compression fees, operating and maintenance costs associated with our gathering systems (which were conveyed to Vinland in connection with the Nami Restructuring Plan) and other customary charges. Production taxes are a function of volumes and revenues generated from production. Ad valorem taxes vary by state/county and are based on the value of our reserves. Lease operating expenses increased $0.3 million to $4.9 million for the year ended December 31, 2006 as compared to the year ended December 31, 2005 due to the 100 additional wells drilled in 2006. On a per Mcfe basis, lease operating expenses declined 5% to $1.12 in 2006 as compared to $1.18 in 2005 due to increased production in 2006. Production taxes increased $0.5 million to $1.8 million or 25% on a per Mcfe basis for the year ended December 31, 2006 as compared to the year ended December 31, 2005 principally due to a significant increase in ad valorem taxes.

	Year Ended December 31,				Percentage Increase
	2006		2005		(Decrease)
Lease operating expenses per Mcfe	$	1.12	$	1.18		(5	)%
Production taxes per Mcfe	$	0.40	$	0.32		25	%

Depreciation, depletion and amortization increased to approximately $8.6 million for the year ended December 31, 2006 from approximately $6.2 million for the year ended December 31, 2005 due to the increase in production from new wells drilled during 2006.

Selling, general and administrative expenses include the costs of our employees and executive officers, related benefits, office leases, professional fees and other costs not directly associated with field operations. Selling, general and administrative expenses decreased $0.7 million during the year ended December 31, 2006 as compared to the year ended December 31, 2005. This represents an 13% decrease for the year ended December 31, 2006 over 2005 resulting from a $2.8 million increase in the amount of capitalized internal costs incurred in connection with the development of natural gas and oil reserves offset by a one-time non-recurring $1.2 million litigation settlement and related legal costs.

Interest and financing expenses were approximately $7.4 million for the year ended December 31, 2006 compared to approximately $4.6 million for the year ended December 31, 2005 primarily due to increased debt levels associated with drilling additional wells and rising interest rates.

Year Ended December 31, 2005 Compared to Year Ended December 31, 2004

Revenues

Natural gas and oil sales increased to approximately $40.3 million from approximately $23.9 million for the year ended December 31, 2005 as compared to the year ended December 31, 2004. The key revenue measurements were as follows:

	Year Ended December 31, 2005			Year Ended December 31, 2004			Percentage Increase (Decrease)
Net Production:
Total Production (MMcfe)		3,894			2,911			34	%
Average Daily production (Mcfe/d)		10,669			7,975			34	%
Average Sales Price per Mcfe:
Average sales price (including hedges)		$	7.77		$	6.17		26	%
Average sales price (excluding hedges)		$	10.35		$	8.20		26	%

The increase in natural gas and oil sales was due to the 34% increase in production as a result of the drilling of 120 wells in 2005 in addition to a 26% increase in the sales price received.

Hedging Activities

We hedged approximately 68% of our 2005 natural gas production, which resulted in revenues that were approximately $10.0 million lower than we would have achieved at unhedged prices. We hedged approximately 91% of our 2004 natural gas production, which resulted in revenues that were approximately $5.9 million lower than we would have achieved at unhedged prices. The derivative contracts entered into in 2005 and 2004 were not specifically designated as hedges under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities and therefore did not qualify for hedge accounting treatment. As a result, the change in the fair value of these natural gas derivative contracts are marked to market in our earnings each period and resulted in $18.8 million and $1.0 million in expense in 2005 and 2004, respectively. Further, these amounts represent non-cash income or expenses. Excluding the effect of these non-cash items, net income would be $8.2 million and $6.3 million for the years ended December 31, 2005 and 2004, respectively.

Costs and Expenses

Production costs consist of the lease operating expenses, production taxes (severance and ad valorem taxes), gathering and compression fees, operating and maintenance costs associated with our gathering

systems and other customary charges. Production taxes are a function of volumes and revenues generated from production. Ad valorem taxes vary by state/county and are based on the value of our reserves. Lease operating expenses increased to approximately $4.6 million for the year ended December 31, 2005 from approximately $2.4 million for the year ended December 31, 2004, due to the increase in the number of wells drilled during 2005. On a per Mcfe basis, lease operating expenses increased by 42% to $1.18, compared to $0.83 for the prior period, principally due to the drilling of 118 wells in 2005. Production taxes increased $0.6 million to $1.2 million or 52% for the year ended December 31, 2005 as compared to the year ended December 31, 2004 principally due to a significant increase in revenue from increased production and increased average sales price realized.

	Year Ended December 31, 2005			Year Ended December 31, 2004			Percentage Increase (Decrease)
Lease operating expenses per Mcfe		$	1.18		$	0.83		42	%
Production taxes per Mcfe		$	0.32		$	0.21		52	%

Depreciation, depletion and amortization increased to approximately $6.2 million for the year ended December 31, 2005 from approximately $4.0 million for the year ended December 31, 2004, due to the increase in production from new wells drilled during 2005.

Selling, general and administrative expenses increased to approximately $5.9 million from approximately $3.2 million during the year ended December 31, 2005 as compared to the year ended December 31, 2004. The increase in selling, general and administrative expenses was due to our rapidly growing operations and increasing our staffing level to manage the additional wells drilled in 2005.

Interest and financing expenses were approximately $4.6 million for the year ended December 31, 2005 as compared to approximately $1.5 million for the year ended December 31, 2004, primarily due to increased debt levels associated with drilling additional wells.

Capital Resources and Liquidity

Our primary source of capital since 1999 has been our cash flow from operations combined with borrowings from our bank and institutional sources. Net cash provided by operating activities for the year ended December 31, 2006 was $16.1 million. Net cash provided by operating activities was $10.5 million for the year ended December 31, 2005. We expect to continue to generate cash flow sufficient to support our projected maintenance capital expenditures. Upon completion of the offering and application of the net proceeds, we expect to have approximately $99.1 million of unused borrowing capacity available under our reserve-based credit facility to help finance our future acquisitions.

We expect to fund our maintenance capital expenditures for the twelve months ending September 30, 2008 with cash flow from operations, while funding any acquisition capital expenditures that we might incur with borrowings under our reserve-based credit facility. We do not currently have any expected acquisition capital expenditures through the twelve-month period ending September 30, 2008, although that may change if acquisition opportunities become available to us in that period. We also estimate that we will have sufficient cash flow from operations after funding our maintenance capital expenditures to enable us to make our quarterly cash distributions to unitholders through September 30, 2008. See “Cash Distribution Policy and Restrictions Distributions.”

In the event that we acquire additional natural gas or oil properties that exceed our existing capital resources, we expect that we will finance those acquisitions with a combination of expanded or new debt facilities and, if necessary, new equity issuances. The ratio of debt and equity issued will be determined by our management and our board of directors as deemed appropriate for our unitholders.

Cash Flow from Operations

Net cash provided by operating activities was $16.1 million during the year ended December 31, 2006, compared to $10.5 million during the year ended December 31, 2005 and $9.6 million during the year ended December 31, 2004. The increase in net cash provided by operating activities in 2006 was substantially due to increased revenues, partially offset by increased expenses, as discussed above in “—Results of Operations.” Changes in current assets and liabilities reduced cash flow from operations by $1.4 million in 2006, $3.9 million in 2005 and $0.8 million in 2004.

Our cash flow from operations is subject to many variables, the most significant of which is the volatility of natural gas prices. Natural gas prices are determined primarily by prevailing market conditions, which are dependent on regional and worldwide economic and political activity, weather and other factors beyond our control. Our future cash flow from operations will depend on our ability to maintain and increase production through our drilling program and acquisitions, as well as the prices of natural gas and oil.

We enter into hedging arrangements to reduce the impact of natural gas price volatility on our cash flow from operations. Currently, we use a combination of fixed-price TECO swaps and NYMEX put options to hedge natural gas prices. Our fixed-priced swaps in place from July 1, 2007 through 2011 hedge approximately 80% of our expected production from wells producing at March 31, 2007 at a weighted average price of $8.33 per MMBtu. However, as a result of expected production from wells that began or are expected to begin producing after March 31, 2007, our fixed-price TECO swaps hedge approximately 60% of our total production for the twelve month period ending September 30, 2008 at $9.00 per MMBtu. In addition, we also have purchased NYMEX put options with a floor of $7.50 per MMBtu covering a substantial portion of our remaining total expected gas production through 2009.

By hedging a significant portion of our natural gas production, we have mitigated, but not eliminated, the potential effects of changing prices on our cash flow from operations for those periods. While mitigating negative effects of falling commodity prices, these derivative contracts also limit the benefits we would receive from increases in commodity prices. It is our policy to enter into derivative contracts only with counterparties that are major, creditworthy financial institutions deemed by management as competent and competitive market makers. The following table summarizes, for the periods indicated, our hedges currently in place through December 31, 2011. The fixed-price swap transactions are settled based upon the TECO Inside FERC Index and the put options are settled based on the NYMEX price of natural gas at Henry Hub on the last trading day of the month. Settlement occurs on the 25th day following the production month for the swaps and collars and on the 5th day following the production month for the put options.

	Fixed-Price Swap Volumes (MMBtu)		Average Swap Price ($/MMBtu)			Put Option Volumes (MMBtu)		Fixed Price Floor ($/MMBtu)
Period from July 1, and February 1, 2007 through December 31, 2007 (1)		1,708,357		$	9.00		1,356,480		$	7.50
Period from January 1, 2008 through December 31, 2008		3,016,134		$	9.00		2,211,366		$	7.50
Period from January 1, 2009 through December 31, 2009		2,657,046		$	8.85		1,840,139		$	7.50
Period from January 1, 2010 through December 31, 2010		2,387,640		$	7.53		—		$	—
Period from January 1, 2011 through December 31, 2011		2,196,012		$	7.15		—		$	—

(1) From July 1, 2007 for fixed-price swap contracts and February 1, 2007 for put options.

Investing Activities—Acquisitions and Capital Expenditures

Our capital expenditures were $37.4 million in the year ended December 31, 2006 and $37.1 million and $19.6 million for the years ended December 31, 2005 and 2004, respectively. The total for 2006 includes $28.9 million for drilling, development and exploitation of natural gas and oil properties, and $8.5 million for furniture, fixtures and equipment which includes expenditures for extensions of the gathering system and related midstream activities. There were no acquisitions during 2006. The totals for 2005 and 2004 include $34.4 million and $18.9 for drilling, development and exploitation of natural gas properties, and $2.7 million and $0.7 million for furniture, fixtures and equipment, respectively.

We currently anticipate that our drilling budget for 2007, which predominantly consists of drilling and equipment, will be funded through cash from operations and borrowings under our reserve-based credit facility. As of June 30, 2007, we had $6.5 million available for borrowing under our reserve-based credit facility. Giving effect to this offering and the application of the net proceeds, our borrowing capacity is expected to be approximately $99.1 million upon completion of this offering, assuming the current borrowing base of $112.5 million. Based upon management’s current natural gas price expectations for the twelve months ending September 30, 2008, we anticipate that the proceeds of this offering, our cash flow from operations and available borrowing capacity under our reserve-based credit facility will exceed our planned capital expenditures and other cash requirements for the twelve months ending September 30, 2008. However, future cash flows are subject to a number of variables, including the level of natural gas production and prices. There can be no assurance that operations and other capital resources will provide cash in sufficient amounts to maintain planned levels of capital expenditures.

Financing Activities

Reserve-Based Credit Facility

On January 3, 2007, our operating company, Vanguard Natural Gas, LLC (formerly Nami Holding Company, LLC), entered into a reserve-based credit facility under which our initial borrowing base was set at $115.5 million. As of September 1, 2007, our borrowing base was reduced to $112.5 million. The borrowing base of our reserve-based credit facility is subject to $1 million reductions per month until our next borrowing base redetermination date of October 1, 2007. This reserve-based credit facility is filed as an exhibit to the registration statement of which this prospectus is a part. The reserve-based credit facility is available for our general limited liability company purposes, including, without limitation, capital expenditures and acquisitions. Our obligations under the reserve-based credit facility are secured by substantially all of our assets.

As of June 30, 2007, we had $109.0 million outstanding under our reserve-based credit facility. We used the borrowings under the reserve-based credit facility to:

· repay approximately $98.5 million of outstanding long-term debt and associated interest and pre-payment fees;

· pay $2.4 million for the termination of existing hedge obligations for 2007;

· purchase $6.5 million in natural gas put options with respect to 5,407,985 MMBtu of production from February 2007 through 2009;

· pay expenses incurred in connection with the closing of the reserve-based credit facility in January 2007; and

· fund working capital requirements.

As of September 1, 2007, we had $107.8 million outstanding under our reserve-based credit facility. We anticipate that $94.4 million of the net proceeds from this offering will be used to repay borrowings,

and after giving effect to repayments we anticipate making prior to the closing of this offering, we expect to have approximately $13.4 million remaining outstanding under our reserve-based credit facility.

Borrowings under the reserve-based credit facility are available for development, exploitation and acquisition of natural gas and oil properties, working capital and general limited liability company purposes.

At our election, interest is determined by reference to:

· the London interbank offered rate, or LIBOR, plus an applicable margin between 1. 375% and 2.00% per annum; or

· a domestic bank rate plus an applicable margin between 0.25% and 1.00% per annum.

Interest is generally payable quarterly for domestic bank rate loans and at the applicable maturity date for LIBOR loans, but not less frequently than quarterly.

The reserve-based credit facility contains various covenants that limit our ability to:

· incur indebtedness;

· grant certain liens;

· make certain loans, acquisitions, capital expenditures and investments;

· make distributions;

· merge or consolidate; or

· engage in certain asset dispositions, including a sale of all or substantially all of our assets.

The reserve-based credit facility also contains covenants that, among other things, require us to maintain specified ratios or conditions as follows:

· consolidated net income plus interest expense, income taxes, depreciation, depletion, amortization, changes in fair value of derivative instruments and other similar charges, minus all non-cash income added to consolidated net income, and giving pro forma effect to any acquisitions or capital expenditures, to interest expense of not less than 2.5 to 1.0;

· consolidated current assets, including the unused amount of the total commitments, to consolidated current liabilities of not less than 1.0 to 1.0, excluding non-cash assets and liabilities under SFAS No. 133, which includes the current portion of derivative contracts;

· consolidated debt to consolidated net income plus interest expense, income taxes, depreciation, depletion, amortization, changes in fair value of derivative instruments and other similar charges, minus all non-cash income added to consolidated net income, and giving pro forma effect to any acquisitions or capital expenditures of not more than 4.0 to 1.0; and

· maintain unencumbered liquid assets of at least $2 million which includes unused availability under the borrowing base.

Upon completion of this offering, we will have the ability to borrow under the reserve-based credit facility to pay distributions to unitholders as long as there has not been a default or event of default and if the amount of borrowings outstanding under our reserve-based credit facility is less than 50% of the borrowing base.

We believe that we are in compliance with the terms of our reserve-based credit facility. If an event of default exists under the reserve-based credit agreement, the lenders will be able to accelerate the maturity of the credit agreement and exercise other rights and remedies. Each of the following will be an event of default:

· failure to pay any principal when due or any interest, fees or other amount within certain grace periods;

· a representation or warranty is proven to be incorrect when made;

· failure to perform or otherwise comply with the covenants in the credit agreement or other loan documents, subject, in certain instances, to certain grace periods;

· default by us on the payment of any other indebtedness in excess of $2.0 million, or any event occurs that permits or causes the acceleration of the indebtedness;

· bankruptcy or insolvency events involving us or our subsidiaries;

· the entry of, and failure to pay, one or more adverse judgments in excess of $1.0 million or one or more non-monetary judgments that could reasonably be expected to have a material adverse effect and for which enforcement proceedings are brought or that are not stayed pending appeal;

· specified events relating to our employee benefit plans that could reasonably be expected to result in liabilities in excess of $1.0 million in any year; and

· a change of control, which includes (1) an acquisition of ownership, directly or indirectly, beneficially or of record, by any person or group (within the meaning of the Securities Exchange Act of 1934 and the rules of the Securities Exchange Commission) of equity interests representing more than 25% of the aggregate ordinary voting power represented by our issued and outstanding equity interests other than by Nami, or (2) the replacement of a majority of our directors by persons not approved by our board of directors.

Off-Balance Sheet Arrangements

We have no guarantees or off-balance-sheet debt to third parties, and we maintain no debt obligations that contain provisions requiring accelerated payment of the related obligations in the event of specified levels of declines in credit ratings.

Contractual Obligations

A summary of our contractual obligations as of December 31, 2006 is provided in the following table.

	Payments Due by Year(1)
	2007		2008		2009		2010			2011			After 2011		Total
Management compensation(2)	$	200,000	$	200,000	$	150,000		$	—		$	—	$	—	$	550,000
Long-term debt(3)	63,067,500		—		—			—			—		31,000,000		94,067,500
Total	$	63,267,500	$	200,000	$	150,000		$	—		$	—	$	31,000,000	$	94,617,500

(1) This table does not include any liability associated with derivative contracts, asset retirement obligations or those liabilities that have been retained by Vinland.

(2) This table does not include any liability associated with management compensation subsequent to 2009 as there is no estimated termination date of the employment agreements.

(3) This table does not include interest to be paid on the principal balances shown. In addition, all outstanding debt as of December 31, 2006 was repaid with borrowings under a new reserve-based

credit facility in January 2007, the relevant terms of which are described under “—Financing Activities—Reserve-Based Credit Facility.” As of September 1, 2007, we had $107.8 million outstanding under our reserve-based credit facility.

Quantitative and Qualitative Disclosure About Market Risk

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in natural gas prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for purposes other than speculative trading.

Commodity Price Risk

Our major market risk exposure is in the pricing applicable to our natural gas production. Realized pricing is primarily driven by the TECO Inside FERC Index Price and the spot market prices applicable to our natural gas production. Pricing for natural gas production has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices we receive for production depend on many factors outside our control.

We have entered into and anticipate entering into hedging arrangements with respect to a portion of our projected natural gas production through various transactions that hedge the future prices received. These transactions may include price swaps whereby we will receive a fixed-price for our production and pay a variable market price to the contract counterparty. Additionally, we have put options for which we pay the counterparty the fair value at the purchase date. At the settlement date we receive the excess, if any, of the fixed floor over the floating rate. These hedging activities are intended to support our realized natural gas prices at targeted levels and to manage our exposure to natural gas price fluctuations. We do not hold or issue derivative instruments for speculative trading purposes.

Interest Rate Risks

At June 30, 2007, we had debt outstanding of $109.0 million, which incurred interest at floating rates based on LIBOR in accordance with our reserve-based credit facility. Assuming that our debt is not repaid as outlined in “Use of Proceeds,” and if all of the debt remains outstanding for the year ended December 31, 2007, a 1% increase in LIBOR would result in an estimated $1.1 million increase in annual interest expense.

Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations are based upon the consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. Certain 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. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used

in preparation of our financial statements. Below, we have provided expanded discussion of our more significant accounting policies, estimates and judgments. After our initial public offering, we will discuss the development, selection and disclosure of each of these with our audit committee. We believe these accounting policies reflect our more significant estimates and assumptions used in preparation of our financial statements. Please read Note 1 of the Notes to the Consolidated Financial Statements for a discussion of additional accounting policies and estimates made by management.

Full-Cost Method of Accounting for Natural Gas and Oil Properties

The accounting for our business is subject to special accounting rules that are unique to the natural gas and oil industry. There are two allowable methods of accounting for gas and oil business activities: the successful-efforts method and the full-cost method. There are several significant differences between these methods. Under the successful-efforts method, costs such as geological and geophysical (G&G), exploratory dry holes and delay rentals are expensed as incurred, where under the full-cost method these types of charges would be capitalized to the full-cost pool. In the measurement of impairment of gas and oil properties, the successful-efforts method of accounting follows the guidance provided in Statement of Financial Accounting Standards (SFAS) No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” where the first measurement for impairment is to compare the net book value of the related asset to its undiscounted future cash flows using commodity prices consistent with management expectations. Under the full-cost method, the net book value (full-cost pool) is compared to the future net cash flows discounted at 10 percent using commodity prices in effect on the last day of the reporting period (ceiling limitation). If the full-cost pool is in excess of the ceiling limitation, the excess amount is charged through income.

We have elected to use the full-cost method to account for our investment in natural gas and oil properties. Under this method, we capitalize all acquisition, exploration and development costs for the purpose of finding natural gas and oil reserves, including salaries, benefits and other internal costs directly related to these finding activities. For the six month period ending June 30, 2007, there were no internal costs capitalized. For the years 2004, 2005, and 2006 such internal costs capitalized totaled $0.1 million, $1.1 million, and $3.9 million, respectively. Although some of these costs will ultimately result in no additional reserves, we expect the benefits of successful wells to more than offset the costs of any unsuccessful ones. In addition, gains or losses on the sale or other disposition of natural gas and oil properties are not recognized unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves. As a result, we believe that the full-cost method of accounting better reflects the true economics of exploring for and developing natural gas and oil reserves. Our results of operations would have been different had we used the successful-efforts method for our natural gas and oil investments. Generally, the application of the full-cost method of accounting results in higher capitalized costs and higher depletion rates compared to similar companies applying the successful-efforts method of accounting.

Full-Cost Ceiling Test

At the end of each quarterly reporting period, the unamortized cost of natural gas and oil properties, after deducting the asset retirement obligation is limited to the sum of the estimated future net revenues from proved properties using period-end prices, after giving effect to cash flow hedge positions, discounted at 10% and the lower of cost or fair value of unproved properties (“Ceiling Test”).

The calculation of the Ceiling Test and the provision for depletion and amortization are based on estimates of proved reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting the future rates of production, timing, and plan of development as more fully discussed in “—Natural Gas and Oil Reserve Quantities” below. Due to the imprecision in estimating natural gas and oil reserves as well as the potential volatility in natural gas and oil prices and their effect on

the carrying value of our proved natural gas and oil reserves, there can be no assurance that Ceiling Test write-downs in the future will not be required as a result of factors that may negatively affect the present value of proved natural gas and oil properties. These factors include declining natural gas prices, downward revisions in estimated proved natural gas and oil reserve quantities and unsuccessful drilling activities.

At December 31, 2006 and June 30, 2007, we had a cushion (i.e. the excess of the ceiling over our capitalized costs) of $42.1 million and $88.7 million, respectively.

Asset Retirement Obligation

We have obligations to remove tangible equipment and restore land at the end of a natural gas or oil wells life. Our removal and restoration obligations are primarily associated with plugging and abandoning wells. Estimating the future plugging and abandonment costs requires management to make estimates and judgments inherent in the present value calculation of the future obligation. These include ultimate plugging and abandonment costs, inflation factors, credit adjusted discount rates, and timing of the obligation. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligation liability, a corresponding adjustment is made to the natural gas and oil property balance.

Natural Gas and Oil Reserve Quantities

Our estimate of proved reserves is based on the quantities of natural gas and oil that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. Netherland Sewell & Associates, Inc. prepares a reserve and economic evaluation of all our properties on a well-by-well basis.

Reserves and their relation to estimated future net cash flows impact our depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. We prepare our reserve estimates, and the projected cash flows derived from these reserve estimates, in accordance with SEC guidelines. The independent engineering firm described above adheres to the same guidelines when preparing their reserve reports. The accuracy of our reserve estimates is a function of many factors including the following: the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions and the judgments of the individuals preparing the estimates.

Our proved reserve estimates are a function of many assumptions, all of which could deviate significantly from actual results. As such, reserve estimates may materially vary from the ultimate quantities of natural gas, natural gas liquids and oil eventually recovered.

Revenue Recognition

Sales of natural gas and oil are recognized when natural gas has been delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured, and the sales price is fixed or determinable. We sell natural gas on a monthly basis. Virtually all of our contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of natural gas, and prevailing supply and demand conditions, so that the price of the natural gas fluctuates to remain competitive with other available natural gas supplies. As a result, our revenues from the sale of natural gas will suffer if market prices decline and benefit if they increase without consideration of hedging. We believe that the pricing provisions of our natural gas contracts are customary in the industry.

We currently use the “Net-Back” method of accounting for transportation arrangements of our natural gas sales. We sell natural gas at the wellhead and collect a price and recognize revenues based on the wellhead sales price since transportation costs downstream of the wellhead are incurred by our customers and reflected in the wellhead price.

Gas imbalances occur when we sell more or less than our entitled ownership percentage of total gas production. Any amount received in excess of our share is treated as a liability. If we receive less than our entitled share the underproduction is recorded as a receivable. We did not have any significant gas imbalance positions at December 31, 2004, 2005 or 2006 or at June 30, 2007.

Price Risk Management Activities

We periodically use derivative financial instruments to achieve a more predictable cash flow from our natural gas production by reducing our exposure to price fluctuations. Currently, these transactions are swaps, collars and put options. We account for these activities pursuant to SFAS No. 133—Accounting for Derivative Instruments and Hedging Activities, as amended. This statement establishes accounting and reporting standards requiring that derivative instruments (including certain derivative instruments embedded in other contracts) be recorded at fair market value and included in the balance sheet as assets or liabilities.

The accounting for changes in the fair market value of a derivative instrument depends on the intended use of the derivative instrument and the resulting designation, which is established at the inception of a derivative instrument. SFAS No. 133 requires that a company formally document, at the inception of a hedge, the hedging relationship and the company’s risk management objective and strategy for undertaking the hedge, including identification of the hedging instrument, the hedged item or transaction, the nature of the risk being hedged, the method that will be used to assess effectiveness and the method that will be used to measure hedge ineffectiveness of derivative instruments that receive hedge accounting treatment.

We did not specifically designate the derivative instruments we established in 2004, 2005 and 2006 as hedges under SFAS No. 133, even though they protected us from changes in commodity prices. Therefore, the mark to market of these instruments was recorded in our current earnings. Further, these mark to market amounts represent non-cash charges. The derivative instruments we established in 2007 as well as future derivative instruments will be designated as hedges under SFAS No. 133. Had no hedges been in place, we would have received additional revenue of $5.9 million, $10.0 million and $2.2 million during 2004, 2005 and 2006, respectively. In January 2007, we terminated existing hedges at a cost of approximately $2.8 million, of which $0.8 million is reflected as a realized loss from derivative contracts on the statement of operations for the six months ended June 30, 2007.

For derivative instruments designated as cash flow hedges, changes in fair market value, to the extent the hedge is effective, are recognized in other comprehensive income until the hedged item is recognized in earnings. Hedge effectiveness is assessed at least quarterly based on total changes in the derivative instrument’s fair market value. Any ineffective portion of the derivative instrument’s change in fair market value is recognized immediately in earnings.

Stock Based Compensation

We account for Stock Based Compensation pursuant to SFAS No. 123(R)—Share-Based Payment. SFAS No. 123(R) requires an entity to recognize the grant-date fair-value of stock options and other equity-based compensation issued to employees in the income statement and eliminates the alternative to use the intrinsic value method of accounting that was provided in SFAS No. 123, which generally resulted in no compensation expense recorded in the financial statements related to the issuance of equity awards to employees. It establishes fair value as the measurement objective in accounting for share-based payment

arrangements and requires all companies to apply a fair-value-based measurement method in accounting for generally all share-based payment transactions with employees. On March 29, 2005, the SEC staff issued SAB No. 107, Share-Based Payment, to express the views of the staff regarding the interaction between SFAS No. 123(R) and certain SEC rules and regulations and to provide the staff’s views regarding the valuation of share-based payment arrangements for public companies.

In April 2007, certain members of management were granted 365,000 restricted Class B units which vest over two years from the date of our initial public offering. In addition, another 55,000 restricted Class B units were issued to two new employees in August 2007, which will vest over three years. There are an additional 40,000 Class B units available to be issued in the future. These units were granted as partial consideration for services to be performed under employment contracts and thus will be subject to accounting for these grants under SFAS No. 123(R)—Share-Based Payment.

With respect to the 420,000 restricted Class B units granted and the granting of 40,000 common units to future employees and/or board members following the completion of this offering, we expect to incur $2.1 million, $3.2 million, $2.2 million and $0.2 million in non-cash compensation expense for the years ended 2007, 2008, 2009 and 2010, respectively. For the six months ended June 30, 2007, we recorded $0.6 million of non-cash compensation expense. Non-cash compensation expense to be incurred on the 40,000 common units to be issued to employees and/or directors upon the completion of this offering will be determined based on the trading price of the units when they are granted.

New Accounting Pronouncements Issued But Not Yet Adopted

In September 2006, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 157, Fair Value Measurements (“SFAS 157”). SFAS 157 provides guidance for using fair value to measure assets and liabilities and requires additional disclosure about the use of fair value measures, the information used to measure fair value, and the effect fair-value measurements have on earnings. The primary areas in which we utilize fair value measures are valuing derivative financial instruments and asset retirement obligations. SFAS 157 does not require any new fair value measurements. SFAS 157 is effective January 1, 2008. We are in the process of evaluating the impact that SFAS 157 will have on our consolidated financial statements.

In February 2006, the FASB issued SFAS No. 155, Accounting for Certain Hybrid Financial Instruments (“SFAS 155”), which amends SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities (“SFAS 133”) and SFAS No. 140, Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities (“SFAS 140”). SFAS 155 simplifies the accounting for certain derivatives embedded in other financial instruments by allowing them to be accounted for as a whole if the holder elects to account for the whole instrument on a fair value basis. SFAS 155 also clarifies and amends certain other provisions of SFAS 133 and SFAS 140. SFAS 155 is effective for all financial instruments acquired, issued or subject to a remeasurement event occurring after January 1, 2007. We do not expect the adoption of SFAS 155 to have a material impact on our consolidated financial statements.

Recently Adopted Accounting Pronouncements

In March 2005, the FASB issued FASB Interpretation (FIN) No. 47, Accounting for Conditional Asset Retirement Obligations. This Interpretation clarifies the definition and treatment of conditional asset retirement obligations as discussed in SFAS No. 143, Accounting for Asset Retirement Obligations. A conditional asset retirement obligation is defined as an asset retirement activity in which the timing and/or method of settlement are dependent on future events that may be outside the control of the company. FIN No. 47 states that a company must record a liability when incurred for conditional asset retirement obligations if the fair value of the obligation is reasonably estimable. This Interpretation is intended to provide more information about long-lived assets, more information about future cash outflows for these obligations and more consistent recognition of these liabilities. We adopted FIN No. 47 on December 31, 2005 and its adoption did not have a material impact on our consolidated financial statements.

BUSINESS

Overview

We owned working interests in 891 gross (805 net) productive wells at June 30, 2007 and our average net production for the twelve months ended December 31, 2006 and the six months ended June 30, 2007 was 11,995 Mcfe per day and 11,925 per day, respectively. We also have 40% of our predecessor’s working interest in the known producing horizons in approximately 95,000 gross undeveloped acres surrounding or adjacent to our existing wells located in southeast Kentucky and northeast Tennessee. In the separation, Vinland was conveyed the remaining 60% of our predecessor’s working interest in the known producing horizons in this acreage and 100% of our predecessor’s working interest in depths above and 100 feet below our known producing horizons. Vinland acts as the operator of our existing wells and all of the wells that we will drill in this area. Approximately 25%, or 16.9 Bcfe, of our pro forma estimated proved reserves as of March 31, 2007 were attributable to this 40% working interest of our predecessor. In addition, we own a contract right to receive approximately 99% of the net proceeds from the sale of production from certain oil and gas wells, which accounted for approximately 5% of our pro forma estimated proved reserves as of March 31, 2007. Our estimated proved reserves at March 31, 2007 were 66.7 Bcfe, of which approximately 98% were natural gas and 75% were classified as proved developed. Our properties, including our working interest in the known producing horizons in approximately 95,000 gross undeveloped acres, fall within an approximate 750,000 acre area, which we refer to in this prospectus as the “area of mutual interest,” or AMI. We have agreed with Vinland until January 1, 2012 to offer the other the right to participate in any acquisition, exploitation and development opportunities that arise in the AMI, subject however to Vinland’s right to consummate up to two acquisitions with a purchase price of $5 million or less annually without a requirement to offer us the right to participate in such acquisitions.

Our average pro forma proved reserves-to-production ratio, or average reserve life, is approximately 15 years based on our estimated pro forma proved reserves as of March 31, 2007 and our production for the twelve months ended March 31, 2007. During 2006, we drilled 100 gross wells (87 of which we retained in the Nami Restructuring Plan, while the other 13 wells were located outside the AMI and not producing at the time of the separation and were thus conveyed to Vinland). We have drilled 41 gross (16 net) wells for the six months ended June 30, 2007. As reflected in the reserve report, as of March 31, 2007, we had identified 338 proved undeveloped drilling locations and over 171 other drilling locations on our leasehold acreage. Pursuant to our participation agreement with Vinland, Vinland generally has control over our drilling program and the sole right to determine which wells are drilled until January 5, 2011. During this period, we will meet with Vinland on a quarterly basis to review Vinland’s proposal to drill not less than 25 nor more than 40 gross wells, in which we will own an approximate 40% working interest, in any quarter. Up to 20% of the proposed wells may be carried over and added to the wells to be drilled in the subsequent quarter, provided that Vinland is required to drill at least 100 gross (approximately 40 net) wells per calendar year. If Vinland proposes the drilling of less than 25 gross wells in any quarter, we have the right to propose the drilling of up to a total of 14 wells, in which we will own an approximate 100% working interest, in a given quarterly period. Based on our production rate at March 31, 2007 and June 30, 2007, we believe we need to drill approximately 130 gross (52 net) wells per year to maintain our production at current levels. By contrast, based upon a sensitivity analysis prepared by NSAI, if Vinland only drills its minimum commitment of 100 gross wells per calendar year, our total production is expected to decline an average of approximately 2.7% per year for the three-year period beginning March 31, 2007.

If Vinland drills its minimum commitment, we do not have the ability to drill our own additional wells in the AMI. If either party elects not to participate in the drilling of the proposed wells or future operations with respect to drilled wells, such party forfeits all right, title and interest in the natural gas and oil production that may be produced from such wells. The participation agreement will remain in place until January 5, 2012 and shall continue thereafter on a year to year basis until such time as either party elects to terminate the agreement. The obligations of the parties with respect to the drilling program described above will expire on January 5, 2011, after which we each will have the right to propose the drilling of wells within the AMI and thereby offer participation in such proposed drilling to the other party and if either party elects not to participate in such proposed drilling or future operations with respect to drilled wells, such party forfeits all right, title and interest in the natural gas and oil production that may be produced from such wells. Please read “Certain Relationships and Related Party Transactions.”

The Appalachian Basin is one of the country’s oldest natural gas producing regions characterized by long-lived reserves and predictable decline rates. During the first several years of production, Appalachian Basin wells generally experience higher initial production rates and decline rates which are followed by an extended period of significantly lower production rates and decline rates. For example, the initial production rate of our new wells may be as high as 80 to 100 Mcf per day while our average production rate during 2006 per well was 16 Mcfe per day. The average well production in the Appalachian Basin is 10 Mcf per day or less and decline rates typically range from 2% to 6% per year.

The Appalachian Basin spans more than seven states in the largest natural gas consuming region of the United States. The close proximity to major natural gas consuming markets in the northeastern United States results in lower transportation costs to these markets relative to natural gas produced in other regions, contributing to the premium pricing for Appalachian production relative to NYMEX natural gas prices. Further, supply of natural gas from the Midwest, Rockies and Canadian regions may face transportation and storage capacity constraints during peak winter season.

Reserves in the Appalachian Basin have typically had a high degree of step-out development success; that is, as development progresses, reserves from newly completed wells are reclassified from the proved undeveloped to the proved developed category and additional adjacent locations are added to proved undeveloped reserves. As a result, the cumulative amount of total proved reserves tends to increase as development progresses. Wells that we have drilled in the Appalachian Basin generally produce little or no water, contributing to a low cost of operation. In addition, most wells produce dry natural gas, which does not require processing.

Wells in the Appalachian Basin are typically drilled at relatively low cost due to the shallow drilling depths and the ability to use air drilling. Most of the drilling rigs are small pull-down type rigs that can be set up on very small locations that are typically 60 feet wide and 160 feet long. These small rigs can be transported to the drilling locations at relatively low cost. Further, the use of air drilling greatly reduces the size of any pits for drilling fluids needed on location. Appalachian wells typically are drilled on relatively close spacing of between 20 to 40 acres per well due to the low permeability of the producing formations. Generally, the distance between wells is less than 1,500 feet, and wells are located within 1,000 feet from the closest pipeline.

Our activities are concentrated in the major geologic producing formations within the southern portion of the Appalachian Basin: primarily the Big Lime and Devonian Shale and secondarily in the Maxon, Chattanooga and Monteagle Shales.

Business Strategies

· Work with Vinland to operate our producing properties and maintain production through the development of our large existing leasehold within our area of mutual interest;

· Maintain a conservative capital structure to ensure financial flexibility for opportunistic acquisitions; and

· Hedge to reduce the volatility in our revenues resulting from changes in natural gas and oil prices.

Competitive Strengths

We believe our competitive strengths position us to successfully execute our business strategies. Our competitive strengths are:

· Our High-Quality, Long-Lived Reserve Base. Our properties are located in the Appalachian Basin in Kentucky and Tennessee. These properties typically have a long history of relatively stable production characterized by low to moderate rates of production decline compared to rates generally experienced in conventional production. Our pro forma estimated proved reserves as of March 31, 2007 had an average reserve life of approximately 15 years.

· Our Inventory of Low-Risk, Low-Cost Development Drilling Locations. We have a substantial inventory of what we believe are low risk drilling locations. During the three years ended December 31, 2006, Vinland drilled 299 gross wells on our natural gas and oil properties, all of which were successfully completed as productive wells. As reflected in the reserve report, as of March 31, 2007, we had identified 338 proved undeveloped drilling locations and an additional 171 other locations on our approximately 95,000 gross undeveloped acres of leasehold in Kentucky and Tennessee. Assuming we drill approximately 130 of our identified drilling locations per year, we believe we will be able to maintain our current total production for approximately four years from March 31, 2007, the date of the reserve report. We have entered into a participation agreement with Vinland wherein we will meet with Vinland on a quarterly basis to review the proposed drilling of not less than 25 nor more than 40 gross wells, in which we will own an approximate 40% working interest, in any quarter.

· Our Relationship with Vinland. We believe our ability to maintain our production and grow through acquisitions is enhanced by our relationship with Vinland, an independent natural gas and oil producer owned by our largest beneficial owner. Vinland has operational, technical and development expertise in our operating areas, and operates our wells and participates with us in our development and exploitation drilling program. We and Vinland have established a 750,000-acre area of mutual interest around and adjacent to our existing production. We intend to pursue acquisitions from Vinland as its properties are developed and jointly with Vinland from third-party operators within this area of mutual interest.

· Our Cost of Capital. Unlike many of our corporate competitors, we are not subject to entity-level federal income taxation. In addition, unlike a traditional master limited partnership structure neither our management nor our current owners hold any incentive distribution rights that entitle them to increasing percentages of cash distributions as our distributions grow. We believe that,

collectively, these two factors provide us a lower cost of equity capital than many of our competitors, enhancing our ability to competitively bid for acquisitions.

· Our Significant Financial Flexibility. Following the closing of the offering, we will have $13.4 million in outstanding long-term debt, which will give us, based on our outstanding borrowings as of September 1, 2007, approximately $99.1 million in borrowing capacity under our reserve-based credit facility to fund acquisitions, development and working capital. We may also issue additional units which, combined with our reserve-based credit facility, will provide us with resources to finance future acquisitions and internal development projects.

Our Relationship with Vinland

General. We believe that one of our principal strengths is our relationship with Vinland, an independent energy company that was formed by our predecessor in connection with the separation of our predecessor into our operating subsidiary and Vinland. Nami owns approximately 90% of Vinland and, upon completion of this offering, Nami and certain of his affiliates and related persons will own a 29.7% membership interest in us. In connection with the separation, all of our predecessor’s officers and employees, other than our President and Chief Executive Officer and our Executive Vice President and Chief Financial Officer, were retained by Vinland. We intend to substantially rely on Vinland and its senior management team to operate our assets.Vinland’s senior management team has an average of approximately 25 years of experience operating in the Appalachian Basin and has operated our assets on behalf of our predecessor in southeast Kentucky and northeast Tennessee since 1999. Since its formation in 1999 through the acquisition of producing properties from American Resources, Vinland’s management team has grown our predecessor through the drilling and completion of over 511 gross productive wells as well as through the acquisition of various producing properties. From 2004 through December 31, 2006, our predecessor added an estimated 21.4 Bcfe of proved natural gas and oil reserves through drilling activities. As of June 30, 2007, Vinland operated substantially all of our wells. As of December 31, 2006 on a pro forma basis after giving effect to the Nami Restructuring Plan described below, Vinland had assets consisting of 60% of our predecessor’s working interest in the known producing horizons in approximately 95,000 gross undeveloped acres in the AMI, 100% of our predecessor’s interest in an additional 125,000 undeveloped acres and certain coalbed methane gas rights located in the Appalachian Basin, the rights to any natural gas and oil located on our acreage at depths above and 100 feet below our known producing horizons and certain gathering and compression assets. Vinland intends to rely on contributions from Nami to fund its proportionate share of our drilling program but Nami has no obligation to make such contributions to Vinland.

Acquisition of Assets. A principal component of our business strategy is to grow our asset base and production through the accretive acquisitions of natural gas and oil properties characterized by long-lived, stable production. Vinland’s business strategy is to develop and divest natural gas and oil properties, generally every 12 to 24 months. Vinland’s management team has a track record of acquiring developed and undeveloped natural gas and oil properties in the Appalachian Basin. Vinland is currently undertaking several other natural gas and oil exploration and production projects in Appalachia within and outside of the AMI that are targeting both conventional and unconventional natural gas and oil reserves, including coalbed methane gas. These projects, which include the Oakdale, Harriman and Lake City Fields could entail the drilling of up to 300 additional wells to develop the identified gas producing horizons in these fields. Currently there is no production from any of these projects and all of these projects are outside of the AMI with Vinland. As Vinland develops these projects to the point of commercial production, and potentially other undeveloped properties that it may acquire in the future, it is possible these properties will have characteristics of properties suitable for us and our business strategies. We believe that the complementary nature of Vinland’s and our business strategies, the proximity of our respective asset bases, Nami’s significant equity interest in us and our right to make a first offer on future sales by Vinland of

properties located within our area of mutual interest will provide us with a number of acquisition opportunities from Vinland in the future. Pursuant to our participation agreement with Vinland, Vinland provides us with a right of first offer with respect to the sale by Vinland of any of its natural gas and oil properties within our area of mutual interest subject to a de minimus exception. However, Vinland has no obligation or commitment to sell any such properties to us, and can be expected to act in a manner that is beneficial to its interests. Please read “Certain Relationships and Related Party Transactions—Participation Agreement.”

Operation and Development of Assets. On April 18, 2007 but effective as of January 5, 2007, we entered into various agreements with Vinland, under which we will rely on Vinland to operate our existing producing wells and coordinate our development drilling program. We expect to benefit from the substantial development and operational expertise of Vinland’s management in the Appalachian Basin. Pursuant to our participation agreement with Vinland, Vinland has control over our drilling program and has the sole right to determine which wells are proposed to be drilled. Since the various agreements were executed on April 18, 2007 but were effective as of January 5, 2007, Vinland reimbursed us for the drilling costs and expenses that we incurred on their behalf associated with their interest in the wells drilled between January 5, 2007 and April 18, 2007. In addition, Vinland reimbursed us for selling, general and administrative expenses that we incurred on their behalf between January 5, 2007 and April 18, 2007. We reimbursed Vinland for certain transaction costs and expenses relating to entering into these agreements. Please read “Certain Relationships and Related Party Transactions.”

Under a management services agreement, Vinland advises and consults with us regarding all aspects of our production and development operations and provides us with administrative support services as necessary for the operation of our business. Pursuant to this agreement, we pay Vinland a monthly fee equal to $60 per producing well for the services provided under the agreement. Vinland may, but does not have any obligation to, provide us with acquisition services under the management services agreement. While Vinland is not obligated to provide us with acquisition services, we expect that our mutually beneficial relationship will provide them with an incentive to grow our business by helping us to identify, evaluate and complete acquisitions that will be accretive to our distributable cash. Please read “Certain Relationships and Related Party Transactions—Management Services Agreement.”

Gathering and Compression. Under a gathering and compression agreement that we entered into with Vinland, Vinland will gather, compress, deliver and provide the services necessary for us to market our natural gas production in the area of mutual interest. Vinland will deliver our natural gas production to certain designated interconnects with third-party transporters. We pay Vinland a fee of $0.25 per Mcf, plus our proportionate share of fuel and line loss for producing wells as of January 5, 2007. For all wells drilled after January 5, 2007, we pay Vinland a fee of $0.55 per Mcf, plus our proportionate share of fuel and line loss. The gathering and compression rates will increase by 11% on January 1, 2011, and shall be adjusted annually thereafter based on a published wage index adjustment factor.

Vinland gathers 100% of our current production and we expect Vinland will gather 100% of the wells we expect to drill in 2007. Vinland’s network of natural gas gathering systems permits us to transport production from our wells with fewer interruptions and also minimizes any delays associated with a non-affiliated gathering company extending its lines to our wells. We expect that our relationship with Vinland will enable us to realize:

· faster connection of newly drilled wells to the gathering system;

· control compression costs and fuel use;

· control the monthly nominations on the receiving pipelines to prevent imbalances and penalties; and

· closely track sales volumes and receipts to assure all production values are realized.

Please read “Certain Relationships and Related Party Transactions—Gathering and Compression Agreement.”

Following this offering, we will also assume certain transportation agreements that Vinland currently has with Delta Natural Gas with respect to volumes of gas produced in Kentucky. Delta receives gas from various interconnects with Vinland and redelivers said volumes to Columbia Gas Transmission. We currently pay Delta $0.26 per MMBtu plus a fuel charge equal to 2% of volume for this transportation service.

In addition, following this offering, we will assume a right to 7,000 MMBtu/day of firm transportation that Vinland currently has on the Columbia Gas Transmission system. We currently pay Columbia Gas $0.22 per MMBtu plus a fuel charge equal to 2% of volume for this firm transportation right. This volume is approximately 47% of our total 2007 estimated production.

While our relationship with Vinland is a significant strength, it is also a source of potential conflicts. For example, neither Vinland, nor any of its affiliates, is restricted from competing with us. Vinland or its affiliates may acquire or invest in natural gas and oil properties or other assets outside of the area of mutual interest in the future without any obligation to offer us the opportunity to purchase or own interests in those assets. For example, Vinland is currently undertaking several other natural gas and oil exploration and production projects in Appalachia within and outside of the AMI that are targeting both conventional and unconventional natural gas and oil reserves, including coalbed methane gas.

Description of Our Properties

All of our properties are located in the southern portion of the Appalachian Basin in southeast Kentucky and northeast Tennessee. These properties were either acquired or have been developed through drilling by our predecessor since its inception in 1999.

Our working interest in any particular well will vary based on the lease or leases on which such well is located.

Smepa Field

Our largest property, as measured by current production and by proved reserves is the Smepa Field located in Bell and Leslie Counties, Kentucky. We own an average of a 97% working interest in 95 producing wells in the Smepa Field and our current net production is approximately 3,309 Mcfe per day and our estimated proved reserves as of March 31, 2007 were 19.5 Bcfe. Production from the Smepa Field is primarily from the Big Lime and Chattanooga Shale formations, and our average well depth is approximately 4,000 feet.

Gausdale Field

Our second largest property, as measured by current production and by proved reserves is the Gausdale Field located in Knox and Whitley Counties, Kentucky. We own an average of a 84% working interest in 204 producing wells in the Gausdale Field and our current net production is approximately 2,200 Mcfe per day and our estimated proved reserves as of March 31, 2007 were 12.2 Bcfe. Production from the Gausdale Field is primarily from the Big Lime and Chattanooga Shale formations, and wells in the field range in depth from 1,500 feet to 3,000 feet.

Brushy Branch Field

Our third largest property, as measured by current production and by proved reserves is the Brushy Branch Field located in Knox County, Kentucky. We own an average of a 98% working interest in 88 producing wells in the Brushy Branch Field and our current net production is approximately 1,800 Mcfe

per day and our estimated proved reserves as of March 31, 2007 were 9.8 Bcfe. Production from the Brushy Branch Field is from the Big Lime, Chattanooga Shale and Maxon formations, and wells in the field range in depth from 1,400 feet to 3,000 feet.

Lewis Heirs Field

Our fourth largest property, as measured by current production and by proved reserves is the Lewis Heirs Field located in Bell County, Kentucky. We own a 100% working interest in 67 producing wells in the Lewis Heirs Field and our current net production is approximately 1,020 Mcfe per day and our estimated proved reserves as of March 31, 2007 were 5.2 Bcfe. Production from the Lewis Heirs Field is from the Big Lime, Chattanooga Shale and Maxon formations, and wells in the field range in depth from 1,900 feet to 3,500 feet.

Windrock Field

Our fifth largest property, as measured by current production and by proved reserves is the Windrock Field located in Anderson County, Tennessee. We own an average of a 94% working interest in 60 producing wells in the Windrock Field and our current net production is approximately 1,280 Mcfe per day and our estimated proved reserves as of March 31, 2007 were 4.3 Bcfe. Production from the Windrock Field is from the Monteagle, Ft. Payne and Chattanooga Shale formations, and wells in the field range in depth from 3,200 feet to 4,300 feet.

Other Fields

We own other producing assets in 18 other smaller fields, 16 of which are in Kentucky and two of which are in Tennessee. We own an average of a 92% working interest in the 286 producing wells associated with these other fields and the collective current net production from these properties is approximately 2,200 Mcfe per day.

Other Properties

In addition to the productive wells in the above field descriptions, there are 60 additional productive wells listed in our reserve report located in the above referenced properties for which our reserve engineers assigned no value for purposes of calculating our standardized measure, and as such, these wells are not included in the above descriptions.

Natural Gas Prices

The Appalachian Basin is a mature producing region with well known geologic characteristics. Reserves in the Appalachian Basin typically have a high degree of step-out development success; that is, as development progresses, reserves from newly completed wells are reclassified from the proved undeveloped to the proved developed category and additional adjacent locations are added to proved undeveloped reserves. As a result, the cumulative amount of total proved reserves tends to increase as development progresses. Wells that we have drilled in the Appalachian Basin generally produce little or no water, contributing to a low cost of operation. In addition, most wells produce dry natural gas, which does not require processing. Natural gas produced in the Appalachian Basin typically sells for a premium to New York Mercantile Exchange, or NYMEX, natural gas prices due to the proximity to major consuming markets in the northeastern United States. For the year ended December 31, 2006, the average premium over NYMEX for natural gas delivered to our primary delivery points in the Appalachian Basin on the TECO system was $0.23 per MMBtu, respectively. In addition, most of our natural gas production has historically had a high Btu content, resulting in an additional premium to NYMEX natural gas prices. For the year ended December 31, 2006 and the six months ended June 30, 2007, our average realized natural

gas prices (before hedging), represented a $1.49 per Mcfe and $1.67 per Mcfe, respectively, premium to NYMEX natural gas prices, which accounts for both the basis differential and the Btu adjustments.

Natural Gas and Oil Data

Proved Reserves

The following table presents our estimated net proved natural gas and oil reserves and the present value of the estimated proved reserves at March 31, 2007, based on a reserve report prepared by NSAI. A summary of the reserve report related to estimated proved reserves at March 31, 2007 prepared by NSAI is attached as Appendix C. The estimates of net proved reserves have not been filed with or included in reports to any federal authority or agency other than the Securities and Exchange Commission in connection with this offering. The standardized measure values shown in the table are not intended to represent the current market value of our estimated natural gas and oil reserves.

	As of
	March 31,
	2007
Reserve Data:
Estimated net proved reserves:
Natural gas (Bcf)		65.2
Crude oil (MBbls)		256
Total (Bcfe)		66.7
Proved developed (Bcfe)		49.8
Proved undeveloped (Bcfe)		16.9
Proved developed reserves as% of total proved reserves		75		%
Standardized measure (in millions)(1)		$	179.8
Representative Natural Gas and Oil Prices(2):
Natural gas—NYMEX Henry Hub per MMBtu		$	7.73
Oil—NYMEX WTI per Bbl		$	55.74

(1) Does not give effect to hedging transactions. For a description of our hedging transactions, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Cash Flow from Operations.”

(2) Natural gas and oil prices as of each period end were based on NYMEX prices per MMBtu and Bbl at such date, with these representative prices adjusted by field to arrive at the appropriate net price.

Proved developed reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are proved reserves that are expected to be recovered from new wells drilled to known reservoirs on undrilled acreage for which the existence and recoverability of such reserves can be estimated with reasonable certainty, or from existing wells on which a relatively major expenditure is required to establish production.

The data in the above table represents estimates only. Natural gas and oil reserve engineering is inherently a subjective process of estimating underground accumulations of natural gas and oil that cannot be measured exactly. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and judgment. Accordingly, reserve estimates may vary from the quantities of natural gas and oil that are ultimately recovered. Please read “Risk Factors.”

Future prices received for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. The standardized measure shown should not be construed as the current market value of the reserves. The 10% discount factor used to calculate present value, which is required by Financial Accounting Standard Board pronouncements, is not necessarily the most appropriate discount rate. The present value, no matter what discount rate is used, is materially affected by assumptions as to timing of future production, which may prove to be inaccurate.

From time to time, we engage NSAI to prepare a reserve and economic evaluation of properties that we are considering purchasing. Neither NSAI nor any of their respective employees has any interest in those properties and the compensation for these engagements is not contingent on their estimates of reserves and future net revenues for the subject properties. During 2006 and in the first six months of 2007, we paid NSAI approximately $25,000 and $86,000, respectively, for all reserve and economic evaluations.

Production and Price History

The following table sets forth information regarding net production of natural gas and oil and certain price and cost information for each of the periods indicated:

	Year Ended December 31,						Six Months Ended
	2004		2005		2006		June 30, 2007
Net Production:
Total realized production (MMcfe)	2,911		3,894		4,378			2,158
Average daily production (Mcfe/d)	7,975		10,669		11,995			11,925
Average Realized Sales Prices ($ per Mcfe):
Average sales prices (including hedges)	$	6.17	$	7.77	$	8.22		$	8.06
Average sales prices (excluding hedges)	$	8.20	$	10.35	$	8.72		$	8.83
Average Unit Costs ($ per Mcfe):
Production costs	$	1.04	$	1.50	$	1.52		$	1.55
Selling, general and administrative expenses	$	1.08	$	1.53	$	1.19		$	1.66	(1)
Depreciation, depletion and amortization	$	1.38	$	1.59	$	1.97		$	2.00

(1) Selling, general and administrative expenses for the historical six months ended June 30, 2007 includes $0.6 million non-cash compensation expense related to the 365,000 Class B unit grant to Messrs. Smith and Robert. This non-cash compensation expense increased selling, general and administrative expense by $0.26 per Mcfe for the six months ended June 30, 2007.

Productive Wells

The following table sets forth information at June 30, 2007 relating to the productive wells in which we owned a working interest as of that date. Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which we have an interest, and net wells are the sum of our fractional working interests owned in gross wells.

	Natural Gas Wells
	Gross		Net
Operated		0	0
Non-operated		891	805
Total		891	805

(1) Of the 891 gross (805 net) non-operated productive wells, Vinland operates 874 gross (805 net) of the productive wells on our behalf.

Developed and Undeveloped Acreage

The following table sets forth information as of June 30, 2007 relating to our leasehold acreage.

	Developed Acreage(1)			Undeveloped Acreage(2)				Total Acreage(5)
	Gross(3)		Net(4)	Gross(4)		Net(4)(6)		Gross	Net(6)
Operated		—	—		—		—	—	—
Non-operated		16,620	15,039		94,521		37,808	111,141	52,847

(1) Developed acres are acres spaced or assigned to productive wells. Of the 16,620 gross (15,039 net) developed acreage that is non-operated, Vinland operates 16,332 gross (15,039 net) of the developed acreage on our behalf.

(2) Undeveloped acres are acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas or oil, regardless of whether such acreage contains proved reserves. Of the 94,521 gross (37,808) net undeveloped acreage that is non-operated, Vinland operates 94,521 gross (37,808 net) of the undeveloped acreage on our behalf.

(3) A gross acre is an acre in which a working interest is owned. The number of gross acres is the total number of acres in which a working interest is owned.

(4) A net acre is deemed to exist when the sum of the fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.

(5) Of the 111,141 gross (52,847 net) total acreage that is non-operated, Vinland operates 110,853 gross (52,807 net) of the total acreage on our behalf.

(6) The net undeveloped acreage does not take into account any minority interests held by parties other than Vinland or us. Our net acreage in our particular lease will vary based on the participation of any such minority interest owners.

Drilling Activity

Most of our wells are relatively shallow, ranging from 2,500 to 5,500 feet, and drill through as many as ten potential producing zones. Many of our wells are completed to multiple producing zones and production from these zones may be commingled. Our average well takes 10 days to drill and is expected to have an average cost of $250,000 in the twelve month period ending September 30, 2008. Most of our wells are producing and connected to a pipeline within 30 days after completion. In general, our producing wells have stable production profiles and long-lived production, often with total projected economic lives in excess of 50 years. Once drilled and completed, operating and maintenance requirements for producing wells in the Appalachian Basin are generally low and only minimal, if any, capital expenditures are required.

Since formation of our predecessor in 1999, Vinland has drilled over 511 wells on our properties, all of which were completed and placed on production. As the operator of our properties, Vinland currently utilizes three drilling rigs that are under contract for our 2007 through 2008 drilling program. In 2006, we drilled 100 gross wells, 87 of which we retained in the Nami Restructuring Plan. The other 13 wells were located outside the AMI and not producing at the time of the separation and were thus conveyed to Vinland. As reflected in the reserve report, as of March 31, 2007, we had identified 338 proved undeveloped drilling locations and over 171 other drilling locations in this area. Assuming we drill approximately 130 of our identified drilling locations per year, we believe we will be able to maintain our current total production for approximately four years from March 31, 2007, the date of the reserve report. For the six months ended June 30, 2007, we drilled 41 gross (16 net) wells. For the six months ended

December 31, 2007 we intend to drill 60 gross (24 net) wells and have budgeted $6.0 million for participation in these wells all of which will be operated by Vinland. Of those 60 wells, we estimate that 56 will be located in Kentucky and 4 will be located in Tennessee. As successful development wells in the Appalachian Basin frequently result in the reclassification of adjacent lease acreage from unproved to proved, we expect that a significant number of our unproved drilling locations will be reclassified as proved drilling locations prior to the actual drilling of these locations.

We intend to concentrate our drilling activity on lower risk, development properties. The number and types of wells we drill will vary depending on the amount of funds we have available for drilling, the cost of each well, the size of the fractional working interests we acquire in each well and the estimated recoverable reserves attributable to each well.

The following table sets forth information with respect to wells completed during the years ended December 31, 2004, 2005 and 2006 and the six months ended June 30, 2007. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled, quantities of reserves found or economic value. Productive wells are those that produce commercial quantities of natural gas, regardless of whether they produce a reasonable rate of return.

	Year Ended December 31,						Six Months Ended June 30,
	2004		2005		2006		2007
Gross wells:
Productive		79		120		100		41
Dry		—		—		—		—
Total		79		120		100		41
Net Development wells:
Productive		76		111		96		16
Dry		—		—		—		—
Total		76		111		96		16
Net Exploratory wells:
Productive		3		9		4		0
Dry		—		—		—		—
Total		3		9		4		0

Operations

General

On April 18, 2007 but effective as of January 5, 2007, we entered into various agreements with Vinland, under which we will rely on Vinland to operate our existing producing wells and coordinate our development drilling program. Pursuant to our participation agreement with Vinland, Vinland generally has control over our drilling program and the sole right to determine which wells are drilled until January 5, 2011. During this period, we will meet with Vinland on a quarterly basis to review Vinland’s proposal to drill not less than 25 nor more than 40 gross wells, in which we will own an approximate 40% working interest, in any quarter. Up to 20% of the proposed wells may be carried over and added to the wells to be drilled in the subsequent quarter, provided that Vinland is required to drill at least 100 gross wells per calendar year. If Vinland proposes the drilling of less than 25 gross wells in any quarter, we have the right to propose the drilling of up to a total of 14 wells, in which we will own an approximate 100% working interest, in a given quarterly period. Based on our production rate at March 31, 2007 and June 30, 2007, we believe we need to drill approximately 130 gross (52 net) wells per year to maintain our production at current levels. By contrast, based upon a sensitivity analysis prepared by NSAI, if Vinland

only drills its minimum commitment of 100 gross wells per calendar year, our total production is expected to decline by an average of approximately 2.7% per year for the three-year period beginning March 31, 2007. If Vinland drills its minimum commitment, we do not have the ability to drill our own additional wells in the AMI. If either party elects not to participate in the drilling of the proposed wells or future operations with respect to drilled wells, such party forfeits all right, title and interest in the natural gas and oil production that may be produced from such wells. The participation agreement will remain in place until January 5, 2012 and shall continue thereafter on a year to year basis until such time as either party elects to terminate the agreement. The obligations of the parties with respect to the drilling program described above will expire on January 5, 2011, after which we each will have the right to propose the drilling of wells within the AMI and thereby offer participation in such proposed drilling to the other party and if either party elects not to participate in such proposed drilling or future operations with respect to drilled wells, such party forfeits all right, title and interest in the natural gas and oil production that may be produced from such wells.

Natural Gas and Oil Leases

The typical natural gas and oil lease agreement provides for the payment of royalties to the mineral owner for all natural gas and oil produced from any well drilled on the lease premises. In the Appalachian Basin this amount is typically 1/8th (12.5%) resulting in an 87.5% net revenue interest to us for most leases directly acquired by us. In certain instances, this royalty amount may increase to 1/6th (16.66%) when leases are taken from larger landowners or mineral owners such as coal and timber companies.

Because the acquisition of natural gas and oil leases is a very competitive process, and involves certain geological and business risks in identifying productive areas, prospective leases are often held by other natural gas and oil operators. In order to gain the right to drill these leases, we may elect to farm-in leases and/or purchase leases from other natural gas and oil operators. Typically the assignor of such leases will reserve an overriding royalty interest, ranging from 1/32nd to 1/16th (3.125% to 6.25%), which further reduces the net revenue interest available to us to between 84.375% and 81.25%.

Sometimes these third-party owners of natural gas and oil leases retain the option to participate in the drilling of wells on leases farmed out or assigned to us. Normally the retained interest is a 25% working interest. In this event, our working interest ownership will be reduced by the amount retained by the third-party operator. In all other instances we anticipate owning a 40% working interest in newly drilled wells.

In almost all of the areas we operate in the Appalachian Basin, the surface owner is normally the natural gas and oil owner, thus allowing us to deal with a single owner. This simplifies the research process required to identify the proper owners of the natural gas and oil rights and reduces the per acre lease acquisition cost and the time required to successfully acquire the desired leases.

Principal Customers

For the year ended December 31, 2006, sales of natural gas to North American Energy Corporation, Osram Sylvania, Inc., Dominion Field Services, Inc., BP Energy Company and Eagle Energy Partners, LLC accounted for approximately 32%, 13%, 13%, 10% and 7%, respectively, of our total revenues. Our top five purchasers during the year ended December 31, 2006, therefore accounted for 75% of our total revenues. The agreements with our principal customers governing the sale of natural gas are typically month-to-month marketing contracts with no specific volume or pricing mechanisms, although we currently have two immaterial contracts that are not month-to-month and are based on a fixed fee. We do have one longer-term agreement with Dominion Field Services which expires in December 2007 and accounts for approximately 15% of our production as of June 30, 2007. We do not have any contracts that

have a duration of more than one year. To the extent these and other customers reduce the volumes of natural gas that they purchase from us and they are not replaced in a timely manner with a new customer, our revenues and cash available for distribution could decline. However, if we were to lose a customer, we believe we could identify a substitute purchaser in a timely manner.

Hedging Activities

We enter into hedging arrangements to reduce the impact of natural gas price volatility on our cash flow from operations. Currently, we use a combination of fixed-price TECO swaps and NYMEX put options to hedge natural gas prices. Our fixed-priced swaps in place from July 1, 2007 through 2011 hedge approximately 80% of our expected production from wells producing at March 31, 2007 at a weighted average price of $8.33 per MMBtu. However, as a result of expected production from wells that began or are expected to begin producing after March 31, 2007, our fixed-price TECO swaps hedge approximately 60% of our total production for the twelve month period ending September 30, 2008 at $9.00 per MMBtu. In addition, we also have purchased NYMEX put options with a floor of $7.50 per MMBtu covering a substantial portion of our remaining total expected gas production through 2009.

Competition

The natural gas and oil industry is highly competitive. We encounter strong competition from other independent operators and from major oil companies in acquiring properties, contracting for drilling equipment and securing trained personnel. Many of these competitors have financial and technical resources and staff 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, technical or personnel resources will permit.

We are also affected by competition for drilling rigs and the availability of related equipment. In the past, the natural gas and oil industry has experienced shortages of drilling 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. We are currently utilizing three drilling rigs that are under contract for our 2007-2008 drilling program.

Competition is also strong for attractive natural gas producing properties, undeveloped leases and drilling 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 natural gas and oil 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 drilling operations on those properties, however, 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 drilling operations on a property until we have cured any material title defects on such property. Prior to completing an acquisition of producing natural gas 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 have obtained title opinions on a significant portion of our natural gas properties and believe that we have satisfactory title to our producing properties in accordance with standards generally accepted in the natural gas and oil industry. Our natural gas 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.

Seasonal Nature of Business

Seasonal weather conditions and lease stipulations can limit our drilling and producing activities and other operations in certain areas of the Appalachian region and, as a result, we generally perform the majority of our drilling during the summer months. These seasonal anomalies can pose challenges for meeting our well drilling 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. Generally, but not always, the demand for natural gas decreases during the summer months and increases during the winter months. Seasonal anomalies such as mild winters or hot summers sometimes lessen this fluctuation. In addition, certain natural gas consumers utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer. This can also lessen seasonal demand fluctuations.

Environmental Matters and Regulation

General. Our business involving the acquisition, development and exploitation of natural gas and oil properties is subject to extensive and stringent federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These operations are subject to the same environmental laws and regulations as other similarly situated companies in the natural gas and oil industry. These laws and regulations may:

· require the acquisition of various permits before drilling commences;

· require the installation of expensive pollution control equipment;

· restrict the types, quantities and concentration of various substances that can be released into the environment in connection with drilling and production activities;

· limit or prohibit drilling activities on lands lying within wilderness, wetlands and other protected areas;

· require remedial measures to prevent pollution from historical and ongoing operations, such as pit closure and plugging of abandoned wells;

· impose substantial liabilities for pollution resulting from our operations; and

· with respect to operations affecting federal lands or leases, require preparation of a Resource Management Plan, an Environmental Assessment, and/or an Environmental Impact Statement.

These laws, rules and regulations may also restrict the rate of natural gas and oil production below the rate that would otherwise be possible. The regulatory burden on the natural gas and oil industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly waste handling, disposal and clean-up requirements for the natural gas and oil industry could have a significant impact on our operating costs. We believe that operation of our wells is in substantial compliance with all current applicable environmental laws and regulations and that our continued compliance with existing requirements will not have a material adverse impact on our financial condition and results of operations. However, we cannot predict how future environmental laws and regulations may impact our properties or the operations. For the year ended December 31, 2006 and the six months ended June 30, 2007, we did not incur any material capital expenditures for installation of remediation or pollution control equipment at any of our facilities. 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 or that will otherwise have a material impact on our financial position or results of operations.

Environmental laws and regulations that could have a material impact on the natural gas and oil exploration and production industry include the following:

National Environmental Policy Act. Natural gas and oil exploitation 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 typically prepare an Environmental Assessment to assess 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. All of our current exploitation and production activities, as well as proposed exploitation and development plans, on federal lands require governmental permits that are subject to the requirements of NEPA. This process has the potential to delay or limit the development of natural gas and oil projects.

Waste Handling. The Resource Conservation and Recovery Act, or RCRA, and comparable state laws, regulate the generation, transportation, treatment, storage, disposal and cleanup of “hazardous wastes” as well as the disposal of non-hazardous wastes. Under the auspices of the U.S. Environmental Protection Agency, or EPA, individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. While drilling fluids, produced waters, and many other wastes associated with the exploitation, development, and production of crude oil, natural gas, or geothermal energy constitute “solid wastes”, which are regulated under the less stringent non-hazardous waste provisions, there is no assurance that the EPA or individual states will not in the future adopt more stringent and costly requirements for the handling of non-hazardous wastes or categorize some non-hazardous wastes as hazardous. We believe that we are in substantial compliance with the requirements of RCRA and related state and local laws and regulations, and that we hold all necessary permits and other authorizations to the extent that our wells and the associated operations require them. Although we do not believe the current costs of managing wastes generated by operation of our wells to be significant, any legislative or regulatory reclassification of natural gas and oil exploitation and production wastes could increase our costs to manage and dispose of such wastes.

Hazardous Substance Releases. The Comprehensive Environmental Response, Compensation and Liability Act (CERCLA), also known as “Superfund,” and analogous state laws, impose joint and several liability, without regard to fault or legality of conduct, on persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the owner or operator of the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substance at the site. Under CERCLA, such persons may be liable 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. 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. While materials are generated in the course of operation of our wells that may be regulated as hazardous substances, we have not received any pending notifications that we may be potentially responsible for cleanup costs under CERCLA.

We currently own, lease, or have a non-operating interest in numerous properties that have been used for natural gas and oil exploitation and production for many years. Although we believe that operating and waste disposal practices have been used that were standard in the industry at the time, hazardous substances, wastes, or petroleum hydrocarbons 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 these 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. 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 Federal Water Pollution Control Act, also known as the Clean Water Act and analogous state laws impose restrictions and strict controls on the discharge of pollutants, including produced waters and other natural gas and oil wastes, 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 the relevant state. The Clean Water Act also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by a permit issued by the U.S. Army Corps of Engineers. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations. We believe we are substantial compliance with the requirements of the Clean Water Act.

Air Emissions. The Clean Air Act, and associated state laws and regulations, regulate emissions of various air pollutants through the issuance of permits and the imposition of other requirements. In addition, EPA has developed, and continues to develop, stringent regulations governing emissions of toxic air pollutants at specified sources. Some of our new facilities may be required to obtain permits before work can begin, and existing facilities may be required to incur capital costs in order to comply with new emission limitations. These regulations may increase the costs of compliance for some facilities, and federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance. We believe that we are in substantial compliance with the requirements of the Clean Air Act.

OSHA. We are subject to the requirements of the federal Occupational Safety and Health Act (OSHA) and comparable state statutes. The OSHA hazard communication standard, EPA community right-to-know regulations under the 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 OSHA and comparable requirements.

Other Laws and Regulation. The Kyoto Protocol to the United Nations Framework Convention on Climate Change became effective in February 2005. Under the Protocol, participating nations are required to implement programs to reduce emissions of certain gases, generally referred to as greenhouse gases, that are suspected of contributing to global warming. Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of oil and natural gas, are examples of greenhouse gases regulated by the Kyoto Protocol. Although the United States is not participating in the Kyoto Protocol, the current session of Congress is considering climate change legislation, with multiple bills having already been introduced that propose to restrict greenhouse gas emissions. Also, several states, although not those in which our wells are located, have already adopted regulatory initiatives or legislation to reduce emissions of greenhouse gases. For example, California recently adopted the “California Global Warming Solutions Act of 2006,” which requires the California Air Resources Board to achieve a 25% reduction in emissions of greenhouse gases from sources in California by 2020. Additionally, on April 2, 2007, the U.S. Supreme Court issued its decision in Massachusetts, et al. v. EPA, holding that the federal Clean Air Act provides EPA with the authority to regulate emissions of carbon dioxide and other greenhouse gases from mobile sources. The Supreme Court also determined that EPA had failed to provide an adequate statutory basis for its refusal to regulate greenhouse gases from such sources. The Supreme Court reversed a decision rendered by the U.S. Circuit Court of Appeals for the District of Columbia and remanded the case to the Circuit Court for further proceedings consistent with its ruling, which will presumably require EPA to determine whether greenhouse gases from mobile sources present an endangerment to public health or welfare. Passage of climate control legislation by Congress or a determination by EPA that public health or welfare is endangered by emission of carbon dioxide from mobile sources may result in federal regulation of carbon dioxide emissions and other greenhouse gases. Currently, operation of our wells is not

adversely impacted by existing state and local climate change initiatives and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact our business.

Other Regulation of the Natural Gas and Oil Industry

The natural gas and oil industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the natural gas and oil 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 natural gas and oil industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the natural gas and oil 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 natural gas and oil 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.

Drilling and Production. Our operations are subject to various types of regulation at the federal, state and local levels. These types of regulation include requiring permits for the drilling of wells, drilling 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 drilling 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.

State laws regulate the size and shape of drilling 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 a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction.

Natural Gas Regulation. The availability, terms and cost of transportation significantly affect sales of natural gas. The interstate transportation and sale for resale of natural gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission. Federal and state regulations govern the price and terms for access to natural gas pipeline transportation. The Federal Energy Regulatory Commission’s regulations for interstate natural gas transmission in some circumstances may also affect the intrastate transportation of natural gas.

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In August 2005, Congress enacted the Energy Policy Act of 2005 (“EP Act 2005”). Among other matters, EP Act 2005 amends the Natural Gas Act (“NGA”) to make it unlawful for any entity, as defined in the EP Act 2005, including otherwise non-jurisdictional producers such as us, to use any deceptive or manipulative device or contrivance in connection with the purchase or sale of natural gas or the purchase or sale of transportation services subject to regulation by the Federal Energy Regulatory Commission (“FERC”), in contravention of rules prescribed by the FERC. On January 19, 2006, the FERC issued rules implementing the provision. The rules make it unlawful in connection with the purchase or sale of natural gas subject to the jurisdiction of the FERC, or the purchase or sale of transportation services subject to the jurisdiction of the FERC, for any entity, directly or indirectly, to use or employ any device, scheme, or artifice to defraud; to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or to engage in any act or practice that operates as a fraud or deceit upon any person. The EP Act 2005 also gives the FERC authority to impose civil penalties for violations of the NGA up to $1,000,000 per day per violation. The EP Act 2005 reflects a significant expansion of the FERC’s enforcement authority. We do not anticipate that we will be affected by the EP Act 2005 any differently than other producers of natural gas.

Although natural gas prices are currently unregulated, Congress historically has been active in the area of natural gas regulation. We cannot predict whether new legislation to regulate natural gas might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on the operations of the underlying properties. Sales of condensate and natural gas liquids are not currently regulated and are made at market prices.

State Regulation. The various states regulate the drilling for, and the production, gathering and sale of, natural gas, including imposing severance taxes and requirements for obtaining drilling permits. For example, Kentucky currently imposes a 4.5% severance tax on natural gas and oil production and Tennessee imposes a 3.0% severance tax. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of natural gas resources. States may regulate rates of production and may establish maximum daily production allowables from natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but there can be no assurance that they will not do so in the future. The effect of these regulations may be to limit the amounts of natural gas that may be produced from our wells, and to limit the number of wells or locations we can drill.

The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to occupational safety, resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect upon the unitholders.

Employees

As of September 1, 2007, we had four full time employees. All of our employees work in our Houston office. Under the management services agreement with Vinland, we will rely on Vinland’s employees to operate our existing producing wells and coordinate our development drilling program. As of September 1, 2007, Vinland had 33 full time employees. We also contract for the services of independent consultants involved in land, regulatory, accounting, financial and other disciplines as needed. None of our employees are represented by labor unions or covered by any collective bargaining agreement. We believe that our relations with our employees are satisfactory.

Offices

We entered into a new lease agreement in January 2007 for approximately 2,320 square feet of office space in Houston, Texas. The lease for our Houston office expires in April 2010.

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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 legal or governmental proceedings against us, or contemplated to be brought against us, under the various environmental protection statutes to which we are subject.

Nami Resources Company, LLC, a subsidiary of our predecessor that was retained by Nami in connection with the Nami Restructuring Plan, has been involved in an ongoing dispute with Asher Land and Mineral Company, Ltd., or Asher, pursuant to which Asher claims that Nami Resources did not correctly calculate the royalties paid to it and that it failed to abide by certain terms of the leases relating to the coordination of oil and gas development with coal development activities.

On September 8, 2006, Asher filed a complaint to initiate an action styled Asher Land and Mineral, Ltd. v. Nami Resources Company, LLC, Bell Circuit Court, Civil Action No. 06-CI-00417. In that action, Asher sought damages and rescission of the leases. Before a responsive pleading was filed, Asher voluntarily withdrew its complaint and dismissed that action. On December 15, 2006, Asher filed a new action styled Asher Land and Mineral, Ltd. v. Nami Resources Company, LLC, Bell Circuit Court, Civil Action No. 06-CI-00566. In that action, Asher has made the same allegations as in the prior suit and added a claim for an undetermined amount of punitive damages. Nami Resources filed an answer denying Asher’s claims and filed a counterclaim asserting damages for lost revenue due to Asher’s breach of lease agreements. The parties have exchanged discovery requests. On August 8, 2007, Asher filed motion for leave to file a first amended complaint in order to add claims to set aside and declare void the asset transfers resulting from the Nami Restructuring Plan, and requesting that the defendants be ordered to account for all downstream expenses charged against Asher for royalties and to reimburse Asher for such charges. In addition, Asher seeks to join us and our subsidiaries, as well as various Vinland entities, as defendants in the litigation in an effort to hold us jointly and severally liable to Asher for all damages. On September 6, 2007, Nami Resources filed a response in opposition to Asher’s motion for leave to join additional defendants and file its first amended complaint. We anticipate becoming a party to the litigation, and Nami Resources has begun filing documents with the court on our behalf. Given the preliminary stage of the litigation and the nature of the proceeding, it is not possible to evaluate the likelihood of either a favorable or unfavorable outcome. We have not accrued any liability amounts for this matter.

In connection with the Nami Restructuring Plan, we received a contract right to receive approximately 99% of the net proceeds from the sale of production from certain producing oil and gas wells located within the Asher lease, which accounted for approximately 5% of our pro forma estimated proved reserves as of March 31, 2007. We did not receive an assignment of any working interest in the Asher lease. The Asher lease and the litigation related thereto were retained by Nami Resources. If the Asher lease is terminated or if Nami Resources’ rights to production under wells of which we have contract rights to receive proceeds are adversely affected, we could lose our contract rights to receive such proceeds or it could be adversely affected.

In connection with the Nami Restructuring Plan, Nami Resources and Vinland have agreed to indemnify us and our subsidiaries for all liabilities, judgments and damages that may arise in connection with the litigation referenced above as well as providing for the defense of any such claims. The indemnities agreed to by Nami Resources and Vinland will remain in place until the resolution of the Asher litigation.

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MANAGEMENT

Our Board of Directors

Upon completion of this offering, our board of directors will consist of three members, one of whom will satisfy the independence requirements of NYSE Arca and SEC rules. Our current board of directors consists of three members, Messrs. Lasse Wagene, Thomas M. Blake and Michael J. Cannon. Mr. Cannon will resign from our board of directors immediately following the pricing of our initial public offering. Our current board is expected to appoint Mr. W. Richard Anderson as an independent director. Our current board of directors is expected to appoint one additional independent member of our board of directors within 90 days of the pricing of this offering, and one additional independent member of our board of directors within one year of the pricing of this offering. The current members and the remaining members of the board expected to be appointed following the pricing of this offering will serve until the first annual meeting of the holders of our units following this offering and will be subject to re-election annually at each meeting of unitholders.

The board intends to appoint four functioning committees immediately following the pricing of this offering: an audit committee, a compensation committee, a conflicts committee and a nominating committee. Our current board is expected to appoint Mr. W. Richard Anderson as the Chairman of our audit committee and as a member of the compensation committee, the conflicts committee and the nominating committee immediately following the pricing of this offering. The additional independent directors to be appointed following this offering are also expected to serve on one or more of the committees described below.

Audit Committee. We currently contemplate that the audit committee will consist of up to three directors. Immediately following the pricing of this offering, we will have one member of the audit committee and such member will be independent under the independence standards established by NYSE Arca and SEC rules, and will be our “audit committee financial expert,” as defined under SEC rules. The audit committee will recommend to the board the independent public accountants to audit our financial statements and establish the scope of, and oversee, the annual audit. The committee also will approve any other services provided by public accounting firms. The audit committee will provide assistance to the board in fulfilling its oversight responsibility to the unitholders, the investment community and others relating to the integrity of our financial statements, our compliance with legal and regulatory requirements, the independent auditor’s qualifications and independence and the performance of our internal audit function. The audit committee will oversee our system of disclosure controls and procedures and system of internal controls regarding financial, accounting, legal compliance and ethics that management and the board have established. In doing so, it will be the responsibility of the audit committee to maintain free and open communication between the committee and our independent auditors and about the internal accounting function and management of our company.

Compensation Committee. We currently contemplate that the compensation committee will consist of up to three directors. Immediately following the pricing of this offering, we will have one member of the compensation committee and such member will be independent under the independence standards established by NYSE Arca and SEC rules. The compensation committee will review the compensation and benefits of our executive officers, establish and review general policies related to our compensation and benefits and administer the Long-Term Incentive Plan we intend to adopt prior to the consummation of this offering. The compensation committee will determine the compensation of our executive officers.

Conflicts Committee. We currently contemplate that the conflicts committee will consist of up to three directors. The conflicts committee will 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 our company. Our limited liability company agreement will provide that members of the committee may not be officers or employees of our company or directors, officers or employees of any of our affiliates and must meet the independence standards for service on an audit committee of a board of

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directors as established by NYSE Arca and SEC rules. Any matters approved by the conflicts committee will be conclusively deemed to be fair and reasonable to our company and approved by all of our unitholders.

Nominating Committee. We currently contemplate that the nominating committee will consist of up to three directors. Immediately following the pricing of this offering, we will have one member of the nominating committee and such member will be independent under the independence standards established by NYSE Arca and SEC rules. This committee will nominate candidates to serve on our board of directors and approve director compensation. The nominating committee also will be responsible for monitoring a process to assess director, board and committee effectiveness, developing and implementing our corporate governance guidelines and otherwise taking a leadership role in shaping the corporate governance of our company.

Under the management services agreement, Vinland provides us with legal, accounting, finance and tax services associated with the administration of our properties. We are dependent on Vinland for management of our operations and, pursuant to the management services agreement, we pay Vinland a monthly fee of $60 for each of our producing wells within the AMI in return for the administrative support services contemplated in the agreement and we also reimburse Vinland for the reasonable costs of any additional services it provides to us. The $60 monthly fee is designed to reimburse Vinland for its actual costs for providing these services using their historical costs of providing these services. Our board of directors has the right and the duty to review the services provided, and the costs charged, by Vinland under that agreement. Our board of directors may in the future cause us to hire additional personnel to supplement or replace some or all of the services provided by Vinland, as well as employ third-party service providers. If we were to take such actions, they could increase the overall costs of our operations. For a description of the services that Vinland will provide to us under the management services agreement and our obligation to reimburse Vinland for the costs it incurs in providing those services, please read “Certain Relationships and Related Party Transactions—Management Services Agreement.”

Heightened Independence for Audit Committee Members

As required by the Sarbanes-Oxley Act of 2002, the SEC has adopted rules that direct national securities exchanges and associations to prohibit the listing of securities of a public company if members of its audit committee do not satisfy a heightened independence standard. In order to meet this standard, a member of an audit committee may not receive any consulting fee, advisory fee or other compensation from the public company other than fees for service as a director or committee member and may not be considered an affiliate of the public company. Our board of directors expects that all members of its audit committee will satisfy this heightened independence requirement.

Audit Committee Financial Expert

An audit committee plays an important role in promoting effective corporate governance, and it is imperative that members of an audit committee have requisite financial literacy and expertise. As required by the SEC rules, a public company must disclose whether its audit committee has a member that is an “audit committee financial expert.” Following the pricing of our initial public offering, our current board is expected to appoint Mr. W. Richard Anderson as the Chairman of our audit committee and to designate Mr. Anderson as our “audit committee financial expert.” An “audit committee financial expert” is defined as a person who, based on his or her experience, possesses all of the following attributes:

· An understanding of generally accepted accounting principles and financial statements;

· An ability to assess the general application of such principles in connection with the accounting for estimates, accruals and reserves;

· Experience preparing, auditing, analyzing or evaluating financial statements that present a breadth and level of complexity of accounting issues that are generally comparable to the breadth and level

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of complexity of issues that can reasonably be expected to be raised by a company’s financial statements, or experience actively supervising one or more persons engaged in such activities;

· An understanding of internal controls and procedures for financial reporting; and

· An understanding of audit committee functions

Meetings and Executive Sessions of Board

Our board will hold regular and special meetings at any time as may be necessary. Regular meetings may be held without notice on dates set by the board from time to time. Special meetings of the board may be called with reasonable notice to each member upon request of the chairman of the board or upon the written request of any three board members. A quorum for a regular or special meeting will exist when a majority of the members are participating in the meeting either in person or by conference telephone. Any action required or permitted to be taken at a board meeting may be taken without a meeting, without prior notice and without a vote if all of the members sign a written consent authorizing the action.

Our board of directors will hold regular executive sessions in which non-management board members meet without any members of management present. The purpose of these executive sessions is to promote open and candid discussion among the non-management board members. During such executive sessions, one non-management board member will be designated as the “presiding board member” and will be responsible for leading and facilitating such executive sessions.

Compensation Committee Interlocks and Insider Participation

None of our executive officers serves as a member of the board of directors or compensation committee of any entity that has one or more of its executive officers serving as a member of our board of directors or compensation committee.

During fiscal year 2006, we had no compensation committee. Nami, as our sole owner, determined executive compensation.

Our Board of Directors and Executive Officers

The following table shows information for members of our board of directors and our executive officers. Members of our board of directors and our executive officers are elected for one-year terms.

Name	Age	Position with Our Company
Scott W. Smith	49	President and Chief Executive Officer
Richard A. Robert	41	Executive Vice President and Chief Financial Officer
Britt Pence	46	Vice President of Engineering
Thomas M. Blake	57	Director
Lasse Wagene	35	Director
Michael J. Cannon	45	Director
W. Richard Anderson	53	Director Nominee

Mr. Scott W. Smith is our President and Chief Executive Officer and has served in such capacities since October 2006. Prior to joining us, since July 2004, Mr. Smith was involved in numerous oil and gas activities, including serving as President of Ensource Energy Company, LLC during its tender offer for the units of the Eastern American Natural Trust (NYSE:NGT). He has over 25 years of experience in the energy industry, primarily in business development, marketing, and acquisition and divestiture of producing assets and exploration/exploitation projects in the energy sector. Mr. Smith’s experience includes evaluating, structuring, negotiating and managing business and investment opportunities, including energy investments similar to our targeted investments totaling approximately $400 million as both board member and principal investor in Wiser Investment Company LLC, the largest shareholder in The Wiser Oil Company (NYSE:WZR) until its sale to Forest Oil Corporation (NYSE:FST) in June of 2004. From June 2000 to June 2004, Mr. Smith served on the board of directors of The Wiser Oil Company. Mr. Smith was also a member of the executive committee of The Wiser Oil Company. From

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January of 1998 to June of 1999, Mr. Smith was the co-manager of San Juan Partners, LLC, which established control of Burlington Resources Coal Seam Gas Trust (NYSE:BRU), which was subsequently sold to Dominion Resources, Inc.

Mr. Richard A. Robert is our Executive Vice President and Chief Financial Officer and has served in such capacities since January of 2007. Prior to joining us, Mr. Robert was involved in a number of entrepreneurial ventures and provided financial and strategic planning services to a variety of energy-related companies since 2003. He was Vice President of Finance for Enbridge US, Inc., a natural gas and oil pipeline company, after its acquisition of Midcoast Energy Resources, Inc. in 2001 where Mr. Robert was Chief Financial Officer and Treasurer. He held these positions from 1996 through 2002 and was responsible for acquisition and divestiture analysis, capital formation, taxation and strategic planning, accounting and risk management, and investor relations. Mr. Robert is a certified public accountant. Mr. Robert has also served as a member of the board of directors of Momentum Biofuels, Inc. since May of 2007.

Mr. Britt Pence is our Vice President of Engineering and has served in such capacity since May of 2007. Prior to joining us, since 1997, Mr. Pence was an Area Manager with Anadarko Petroleum Corporation supervising evaluation and exploitation projects in coalbed methane fields in Wyoming and conventional fields in East Texas and the Gulf of Mexico. Prior to joining Anadarko, Mr. Pence served as a reservoir engineer with Greenhill Petroleum Company from 1991-1997 with responsibility for properties in the Permian Basin, South Louisiana and the Gulf of Mexico. From 1983-1991, Mr. Pence served as reservoir engineer with Mobil with responsibility for properties in the Permian Basin. Mr. Pence is a Registered Professional Engineer in the State of Texas.

Mr. Thomas M. Blake is a member of our board of directors and also is currently President and Chief Executive Officer of Vinland, Vinland Energy Gathering, LLC and Vinland Gulf Coast, LLC. Prior to joining Vinland in October of 2006, he was Vice President and General Manager of Appalachian Production Services and Appalachian Energy, an oil and gas production company and contract operating firm with over 3000 wells under management from 2003 to October 2006. From 2001 to 2003, Mr. Blake was Senior Vice President—Engineering and Operations for Columbia Natural Resources, one of the largest producers in Appalachia with over 65 BCF per year of annual production.

Mr. Lasse Wagene is a member of our board of directors and also is Managing Director of Arcturus Capital AS and serves as a financial advisor to Vinland and its affiliates. Prior to his current position, he was a partner and led the Oil Services Investment Banking Group at Carnegie ASA from 2000 to 2004. While at Carnegie, his responsibilities included marketing the bank’s services to European clients and advising clients on European capital markets and merger and advisory transactions. Prior to Carnegie, he was Vice President of Energy Finance at Den Norske Bank in New York and Houston from 1998 through 2000.

Mr. Michael J. Cannon is a member of our board of directors and also is the head of Lehman Brothers MLP Partners Group, or LBMLP, and a Managing Director of Lehman Brothers Inc. Prior to joining LBMLP, Mr. Cannon served as a Managing Director in Lehman Brothers’ Natural Resources investment banking group in New York, where he initiated and built Lehman Brothers’ MLP practice commencing in 1986. Mr. Cannon has worked for 19 years at Lehman Brothers and served as the head of the Lehman Brothers MLP vertical during his entire tenure at the firm before joining LBMLP.

W. Richard Anderson is a director nominee to our board of directors and also is the President, Chief Financial Officer and a director of Prime Natural Resources, a closely-held exploration and production company. Prior to his employment at Prime Natural Resources in January 1999, he was employed by Hein & Associates LLP, a certified public accounting firm, where he served as a partner from 1989 to January 1995 and as a managing partner from January 1995 until October 1998. Mr. Anderson also serves on the boards of directors of Global Santa Fe Corporation, Boots & Coots International Well Control, Inc. and Calibre Energy, Inc.

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COMPENSATION DISCUSSION AND ANALYSIS

Compensation Objectives

Our primary goal with respect to executive compensation has been to attract and retain the most talented and dedicated executives possible. Following the completion of this offering, we also intend to link annual and long-term cash incentives to the achievement of specified performance objectives and to align executives’ incentives with creation of unitholder value. To achieve these goals, we expect that our compensation committee will implement and maintain compensation plans that tie a portion of executive overall compensation to our financial and operational performance, as measured by our ability to generate stable cash flows allowing us to make quarterly cash distributions to our unitholders and over time to increase our quarterly cash distributions. We expect that our compensation committee will evaluate individual executive performance with a goal of setting compensation levels it believes are comparable with executives in other companies of similar size and stage of development engaged in the acquisition, development and exploitation of mature, long-lived natural gas and oil properties while also considering our relative performance and our own strategic goals.

Compensation Committee

Upon consummation of this offering, our board of directors will have a compensation committee that will determine the compensation of our executive officers. We currently contemplate that the compensation committee will consist of up to three directors. Immediately following the pricing of this offering, we will have one member of the compensation committee and such member will be independent under the independence standards established by NYSE Arca and SEC rules. The compensation committee will review the compensation and benefits of our executive officers, establish and review general policies related to our compensation and benefits and administer our Long-Term Incentive Plan.

Compensation Philosophy

During fiscal year 2006, we had no compensation committee, and our compensation process was not yet established for our 2006 executive performance and compensation evaluation. In 2007, we are focused on recruiting and building our management team and, as a result, performance targets have not yet been finalized for 2007. We believe that our initial public offering will establish a basis for comparison to companies with a legal structure similar to a master limited partnership. As such, we expect that our compensation committee will be able to obtain information necessary to fairly and objectively set financial targets and develop a comparable peer group. We currently do not have a policy for establishing the compensation of our executive officers, but we expect that our compensation committee will develop such a policy that may include the review of compensation levels of our peer group.

Elements of Compensation

Executive compensation currently consists of following elements:

Base Salary. Base salaries established for our named executive officers were generally established on the dates of hire by negotiation with the individual officer and by comparison to the compensation packages of similarly positioned officers of other companies in our industry, such as Linn Energy, LLC and Breitburn Energy Partners, L.P. We used the compensation packages of the executive officers of these companies as a starting point for our negotiations.

Incentive Compensation. We believe that long-term performance is achieved through an ownership culture that encourages long-term performance by our executive officers through the use of unit-based awards. We intend to adopt the Vanguard Natural Resources, LLC Long-Term Incentive Plan prior to the consummation of this offering, which will permit the grant of our units, unit options, restricted units, phantom units and unit appreciation rights. The compensation committee will have the authority under the

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plan to award incentive compensation to our executive officers in such amounts and on such terms as the committee determines in its sole discretion.

Currently, we do not maintain any incentive compensation plans based on pre-defined performance criteria. Following the completion of this offering, we expect that the compensation committee will implement and maintain one or more plans that are based on such criteria. Incentive compensation is intended to compensate officers for achieving financial and operational goals and for achieving individual annual performance objectives. These objectives are expected to vary depending on the individual executive, but are expected to relate generally to strategic factors such as expansion of our services and to financial factors such as improving our results of operations and increasing our quarterly cash distributions. The actual amount of incentive compensation for each year will be determined following a review of each executive’s individual performance and contribution to our strategic goals conducted during the first quarter of the next year. Specific performance targets used to determine incentive compensation for each of our executive officers in 2007 have not yet been determined and we expect our compensation committee will make such determinations following the completion of this offering. We expect such performance targets will include increases in our quarterly cash distributions to our unitholders, proved reserves and production.

Other Employee Grants. Prior to the completion of this offering, we intend to grant to Richard A. Robert and Britt Pence options to purchase an aggregate of 100,000 units and 75,000 units, respectively, under our long-term incentive plan with an exercise price equal to the public offering price in this offering and vesting in equal installments over a three year period beginning on the first anniversary of the completion of this offering. The decision to grant Richard A. Robert and Britt Pence these options was made when their employment agreements were negotiated. We also intend to grant annually to certain executive officers, pursuant to their employment agreements, phantom units in amounts equal to 1.0% of our units outstanding at that time. The Company will bear the cost of said grants. The 2008 phantom units will be granted on January 1, 2008 and an additional grant will be made each year thereafter that their employment agreements remain in effect. The amount paid in either cash or units on these phantom units will be in an amount equal to the appreciation in value of the units, if any, from the date of the grant until the determination date, plus cash distributions paid on the units, less an 8% hurdle rate.

These grants are intended to reward these individuals for their prior service with our company and their efforts in connection with this offering, to encourage performance following the completion of this offering, and to align the interests of management with those of our unitholders.

Other Compensation. Our executive officers’ employment agreements provide the executive with certain other benefits, including reimbursement of business and entertainment expenses and life insurance expenses. Each executive is eligible to participate in all benefit plans and programs that are or in the future may be available to other executive employees of our company, including any profit-sharing plan, thrift plan, health insurance or health care plan, disability insurance, pension plan, supplemental retirement plan, vacation and sick leave plan, and other similar plans. The compensation committee in its discretion may revise, amend or add to the officer’s executive benefits and perquisites as it deems advisable. We believe that these benefits and perquisites are typically provided to senior executives of comparable companies in our industry.

Executive Compensation

No compensation was paid to executive officers during 2006.

Employment Agreements

The employment agreements and compensation terms for each of our executive officers were generally established on the dates of hire by negotiation with the individual officer and by comparison to the compensation packages of similarly positioned officers of other companies in our industry, such as

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Linn Energy, LLC and Breitburn Energy Partners, L.P. Mr. Smith was our initial executive officer, and at the time of his hire date, Mr. Smith and Nami negotiated Mr. Smith’s compensation package, the compensation package of a potential Chief Financial Officer, and the aggregate amount of equity grants to be made to all of management, which consists of the 420,000 Class B units issued prior to the completion of this offering and the 40,000 common units to be issued to employees and/or directors following the completion of this offering. Mr. Robert was hired in January 2007 and his employment agreement and compensation terms ultimately consisted of the terms previously negotiated between Mr. Smith and Nami in respect of the Chief Financial Officer. Mr. Pence was hired after the Nami Restructuring Plan, and his employment agreement was negotiated between Mr. Pence and Mr. Smith and approved by Messrs. Blake and Wagene, as members of our board of directors.

Because of their different positions and responsibilities and dates of hire, our executive officers did not each receive the same compensation terms. For example, Mr. Smith received more Class B units than Messrs. Robert and Pence because of his responsibilities as our President and Chief Executive Officer, and Mr. Robert received more Class B units than Mr. Pence because of his responsibilities as our Executive Vice President and Chief Financial Officer. Further, Messrs. Smith and Robert were employees at the time of and assisted with the completion of the Nami Restructuring Plan. In addition, Messrs. Smith and Robert will each receive an annual grant of phantom units in an amount equal to 1.0% of the outstanding units because of their positions and responsibilities as well as their length of employment.

Scott W. Smith. We have entered into an employment agreement with Scott W. Smith, who will serve as our President and Chief Executive Officer. Nami, as our sole owner at the time we hired Mr. Smith, determined the amount of executive compensation to be paid to Mr. Smith. When negotiating the terms of Mr. Smith’s compensation, Nami and Mr. Smith considered the compensation packages of similarly positioned officers of other companies in our industry, such as Linn Energy, LLC and Breitburn Energy Partners, L.P. Mr. Smith’s employment agreement is for a three year term and will renew each year thereafter for a one year term unless cancelled by either party upon 90 days’ prior written notice. The compensation will consist of a base salary of $200,000 per year, subject to increases as determined to be appropriate by our board of directors, and health and other benefits as are standard in the industry. We expect that our board of directors will delegate its authority to modify Mr. Smith’s base salary to its compensation committee, and that the compensation committee will consider specific performance targets such as increases in our quarterly cash distributions to our unitholders, proved reserves and production. Commencing in 2008, Mr. Smith will receive annual grants of phantom units in amounts equal to 1.0% of the units outstanding at the time of each grant. The Company will bear the cost of said grants. The 2008 phantom units will be granted on January 1, 2008, and an additional grant will be made each year thereafter that his employment agreement remains in effect. The amount paid in either cash or units on these phantom units will be in an amount equal to the appreciation in value of the units, if any, from the date of the grant until the determination date (the end of our fiscal year), plus cash distributions paid on the units, less an 8% hurdle rate. The employment agreement was amended at the time of the Nami Restructuring Plan for purposes of establishing the form of management equity compensation and to reduce the vesting period of such equity compensation from three to two years. The purpose of the reduction in vesting terms was to adjust for the amount of time that we expected to lapse prior to the completion of this offering, and such reduction was the only change in compensation to Mr. Smith. The amended employment agreement is included as an exhibit to the registration statement of which this prospectus is a part.

Richard A. Robert. We have entered into an employment agreement with Richard A. Robert, who will serve as our Executive Vice President and Chief Financial Officer. Mr. Robert’s employment agreement was negotiated between Mr. Robert and Mr. Smith and was approved by Nami, as our sole owner. When negotiating the terms of Mr. Robert’s compensation, Nami, Mr. Smith and Mr. Robert considered the compensation packages of similarly positioned officers of other companies in our industry,

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such as Linn Energy, LLC and Breitburn Energy Partners, L.P. Mr. Robert’s employment agreement is for a three year term and will renew each year thereafter for a one year term unless cancelled by either party upon 90 days’ prior written notice. The compensation will consist of a base salary of $200,000 per year, subject to increases as determined to be appropriate by our board of directors, and health and other benefits as are standard in the industry. We expect that our board of directors will delegate its authority to modify Mr. Robert’s base salary to its compensation committee, and that the compensation committee will consider specific performance targets such as our ability to increase our quarterly cash distributions to our unitholders, proved reserves and production. In addition, Mr. Robert will receive options to purchase 100,000 units at the initial public offering price. The term of these options is five years. Commencing in 2008, Mr. Robert will receive annual grants of phantom units in an amount equal to 1.0% of the units outstanding at the time of each grant. The Company will bear the cost of said grants. The 2008 phantom units will be granted on January 1, 2008, and an additional grant will be made each year thereafter that his employment agreement remains in effect. The amount paid in either cash or units on these phantom units will be in an amount equal to the appreciation in value of the units, if any, from the date of the grant until the determination date (the end of our fiscal year), plus cash distributions paid on the units, less an 8% hurdle rate. The employment agreement was amended at the time of the Nami Restructuring Plan for purposes of establishing the form of management equity compensation and to reduce the vesting period of such equity compensation from three to two years. The purpose of the reduction in vesting terms was to adjust for the amount of time that we expected to lapse prior to the completion of this offering, and such reduction was the only change in compensation to Mr. Robert. The amended employment agreement is included as an exhibit to the registration statement of which this prospectus is a part.

Britt Pence. We have entered into an employment agreement with Britt Pence, who will serve as our Vice President of Engineering. Mr. Pence’s employment agreement was negotiated between Mr. Pence and Mr. Smith and approved by Messrs. Blake and Wagene, as members of our board of directors. The agreement is for a three year term and will renew each year thereafter for a one year term unless cancelled by either party upon 90 days’ prior written notice. The compensation will consist of a base salary of $200,000 per year, subject to increases as determined to be appropriate by our board of directors, and health and other benefits as are standard in the industry. We expect that our board of directors will delegate its authority to modify Mr. Pence’s base salary to its compensation committee, and that the compensation committee will consider specific performance targets such as increases in our quarterly cash distributions to our unitholders, proved reserves and production. In addition, Mr. Pence will receive options to purchase 75,000 units at the initial public offering price. The term of these options is five years. The employment agreement is included as an exhibit to the registration statement of which this prospectus is a part.

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Grants of Plan-Based Awards

Prior to the completion of this offering, we intend to grant to Richard A. Robert and Britt Pence options to purchase an aggregate of 100,000 units and 75,000 units, respectively, with an exercise price equal to the public offering price in this offering that are subject to a five year exercise period beginning on the first anniversary of the closing of this offering and immediately vest on the date of grant. Pursuant to their employment agreements, on January 1, 2008, we also intend to grant to Scott W. Smith and Richard A. Robert an annual grant of phantom units in an amount equal to 1.0% of our units outstanding at that time. The amount paid in either cash or units on these phantom units will be in an amount equal to the appreciation in value of the units, if any, from the date of grant until the determination date, plus cash distributions paid on the units, less an 8% hurdle rate. These grants will be made under our long-term incentive plan described below. The following table sets forth the grants of options, restricted units and Class B units we have made or intend to make in connection with this offering under our long-term incentive plan or our Class B unit plan to the named executive officers and to all executive officers and directors as a group.

Name	Grant Date	All Other Unit Awards: Number of Units (#)		Grant Date Fair Value of Unit Awards ($)(a)		All Other Option Awards: Number of Securities Underlying Options (#)		Exercise or Base Price of Option Awards ($/unit)(b)		Grant Date Fair Value of Option Awards ($)(a)
Scott W. Smith	April 18, 2007		240,000		4,320,000		—		—		—
Richard A. Robert	April 18, 2007		125,000		2,250,000		100,000		23.00		76,748
Britt Pence	August 15, 2007		50,000		1,150,000		75,000		23.00		57,561
W. Richard Anderson (c)			5,000		115,000		—		—		—
All executive officers and directors as a group			420,000		7,835,000		175,000		23.00		134,309

(a) Amounts in these columns represent the fair market value of the awards indicated, calculated in accordance with FAS 123R. For option awards, that number is calculated by multiplying the Black-Scholes value by the number of options awarded.

(b) Assumes a public offering price of our common units of $23.00 per unit. This amount will be the actual initial public offering price.

Long-Term Incentive Plan

Prior to the consummation of this offering, we expect to adopt a Vanguard Natural Resources, LLC Long-Term Incentive Plan for employees, consultants and directors and employees of our’s and our affiliates who perform services for us. The long-term incentive plan will consist of: unit grants, unit options, restricted units, phantom units and unit appreciation rights. The long-term incentive plan will limit the number of units that may be delivered pursuant to awards to 1,000,000 units. The plan will be administered by the compensation committee of our board of directors.

The long-term incentive plan does not provide for formulaic or automatic grants of any awards. It is a traditional omnibus plan, i.e., one that permits the grant of various types of awards (options, appreciation rights, restricted units and phantom units) as determined by our board of directors or compensation committee (whichever is administering the long-term incentive plan), in its sole discretion. The long-term incentive plan is designed to give the compensation committee the maximum flexibility in determining when to grant awards, to whom awards will be granted, the type and amount of awards and the general terms (vesting, performance criteria and other matters) of each award. Awards may vary between individuals, between classes of individuals, by year or on any other basis the compensation committee determines to be appropriate.

The only limitations on the compensation committee’s discretion with respect to grants are, in general, (i) no more than 1,000,000 units may be delivered pursuant to awards granted under the long-term

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incentive plan, of which no more than 500,000 may be delivered with respect to restricted unit grants, and the minimum exercise price for options and appreciation rights may not be less than the closing sales price of a unit on the date of grant and (ii) awards may be granted to any of our directors, employees or consultants or any of our affiliates. Like most companies, it is anticipated that the compensation committee will use the services of a compensation consultant in determining which individuals who perform services (directly or indirectly) for our benefit will receive awards, the type of award or awards, the amount and the performance and vesting terms of such awards. It is anticipated that awards will be made only once a year to employees, in general.

Administration. Our board of directors and the compensation committee of the board have the right to alter or amend the long-term incentive plan or any part of the plan from time to time, including increasing the number of units that may be granted, subject to unitholder approval as required by the exchange upon which the units are listed at that time. However, no change in any outstanding grant may be made that would materially reduce the benefits of the participant without the consent of the participant.

Unit Grants. A unit grant is a unit that is vested immediately upon issuance. Upon closing of this offering, no unit grants will be awarded. In the future, the compensation committee may determine to make grants under the plan to employees and members of our board.

Unit Options. A unit option is a right to purchase a unit at a specified price. The long-term incentive plan will permit the grant of options covering units. In the future, the compensation committee may determine to make grants under the plan to employees, consultants and members of our board containing such terms as the committee shall determine. Unit options will have an exercise price that will not be less than the fair market value of the units on the date of grant. In general, unit options granted will become exercisable over a period determined by the compensation committee, although vesting may accelerate upon the achievement of specified financial objectives. In addition, the unit options will become exercisable upon a change in control of our company, unless provided otherwise by the committee. If a grantee’s employment, consulting relationship or membership on the board of directors terminates for any reason, the grantee’s unvested unit options will be automatically forfeited unless, and to the extent, the option agreement or the compensation committee provides otherwise.

Upon exercise of a unit option (or a unit appreciation right settled in units), we will issue new units, acquire units on the open market or directly from any person or use any combination of the foregoing, in the compensation committee’s discretion. If we issue new units upon exercise of the unit options (or a unit appreciation right settled in units), the total number of units outstanding will increase. The availability of unit options and unit appreciation rights is intended to furnish additional compensation to employees and members of our board of directors and to align their economic interests with those of unitholders.

Restricted Units. A restricted unit is a unit that vests over a period of time and that during such time is subject to forfeiture. In the future, the compensation committee may determine to make additional grants of restricted units under the plan to employees, consultants and directors containing such terms as the compensation committee shall determine. The compensation committee will determine the period over which restricted units (and distributions related to such units) granted to employees, consultants and members of our board will vest. The committee may base its determination upon the achievement of specified financial objectives. In addition, the restricted units will vest upon a change of control of our company, as defined in the plan, unless provided otherwise by the committee.

If a grantee’s employment, consulting relationship or membership on the board of directors terminates for any reason, the grantee’s restricted units will be automatically forfeited unless, and to the extent, the compensation committee or the terms of the award agreement provide otherwise. Units to be delivered as restricted units may be units issued by us, units acquired by us in the open market, units acquired by us from any other person or any combination of the foregoing. If we issue new units upon the grant of the restricted units, the total number of units outstanding will increase.

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We intend the restricted units 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 our units. Therefore, plan participants will not pay any consideration for the units they receive, and we will receive no remuneration for the units.

Phantom Units. A phantom unit entitles the grantee to receive a unit upon the vesting of the phantom unit or, in the discretion of the compensation committee, cash equivalent to the value of a unit. In the future, the compensation committee may determine to make grants of phantom units under the plan to employees, consultants and directors containing such terms as the compensation committee shall determine. The compensation committee will determine the period over which future grants of phantom units granted to employees, consultants and members of our board will vest. The committee may base its determination upon the achievement of specified financial objectives. In addition, the phantom units will vest upon a change of control of our company, unless provided otherwise by the committee.

If a grantee’s employment, consulting relationship or membership on the board of directors terminates for any reason, the grantee’s phantom units will be automatically forfeited unless, and to the extent, the compensation committee or the terms of the award agreement provide otherwise. Units to be delivered upon the vesting of phantom units may be units issued by us, units acquired by us in the open market, units acquired by us from any other person or any combination of the foregoing. If we issue new units upon vesting of the phantom units, the total number of units outstanding will increase. The compensation committee, in its discretion, may grant tandem distribution equivalent rights with respect to phantom units that entitle the holder to receive cash equal to any cash distributions made on units while the phantom units are outstanding.

We intend the issuance of any units upon vesting of the phantom units 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 our units. Therefore, plan participants will not pay any consideration for the units they receive, and we will receive no remuneration for the units.

Grants in Connection with Initial Public Offering. Prior to the completion of this offering, we intend to grant to Richard A. Robert and Britt Pence options to purchase an aggregate of 100,000 units and 75,000 units, respectively, with an exercise price equal to the public offering price in this offering that are subject to a five year term beginning on the first anniversary of the closing of this offering and immediately vest on the date of grant.

Unit Appreciation Rights. The long-term incentive plan will permit the grant of unit appreciation rights. A unit appreciation right is an award that, upon exercise, entitles the participant to receive all or part of the excess of the fair market value of a unit on the exercise date over the exercise price established for the unit appreciation right. Such excess may be paid in units, cash or a combination thereof, as determined by the compensation committee in its discretion. Initially, we do not expect to grant unit appreciation rights under our long-term incentive plan. In the future, the compensation committee may determine to make grants of unit appreciation rights under the plan to employees, consultants and directors containing such terms as the committee shall determine. Unit appreciation rights will have an exercise price that will not be less than the fair market value of the units on the date of grant. In general, unit appreciation rights granted will become exercisable over a period determined by the compensation committee. In addition, the unit appreciation rights will become exercisable upon a change of control of our company, unless provided otherwise by the committee. If a grantee’s employment, consulting relationship or membership on the board of directors terminates for any reason, the grantee’s unvested unit appreciation rights will be automatically forfeited unless, and to the extent, the grant agreement or compensation committee provides otherwise.

Amendment, Modification and Termination. Subject to applicable law or stock exchange rules, our board of directors may at any time amend or terminate the long-term incentive plan without unitholder approval. The compensation committee may amend or terminate any outstanding award without approval

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of the participant; however, no such amendment or termination may be made that would otherwise adversely impact a participant, without the consent of the participant.

Class B Units

We have established a series of Class B units to be issued to management pursuant to our Class B unit plan. We issued 240,000 Class B units and 125,000 Class B units to Messrs. Smith and Robert, respectively in April 2007 and issued 50,000 Class B units to Britt Pence and 5,000 units to Patty Avila-Eady on August 15, 2007. There are an additional 40,000 Class B units available to be issued in the future. The Class B units will have substantially the same rights as the common units and, upon vesting, will become convertible at the election of the holder into common units. Unless the context otherwise requires, all references to our “common units” or our “units” refer collectively to our common units and our Class B units, each representing membership interest in us.

Potential Payments upon Termination or Change-in-Control

Trigger Events. An executive officer’s employment agreement will terminate upon the executive’s death or upon the executive’s disability, which is defined as his becoming unable to substantially perform his duties as an employee as a result of sickness or injury, and shall have remained unable to perform any such duties for a period of more than 180 consecutive days in any 12-month period.

We, by action of our board of directors, may also terminate at any time an employment agreement with an executive officer for “cause”, which means: (1) the executive officer’s commission of theft, embezzlement, any other act of dishonesty relating to his employment with us or any willful and material violation of any law, rules or regulation applicable to us, including, but not limited to, those laws, rules or regulations established by the SEC, or any self-regulatory organization having jurisdiction or authority over the executive officer or us, (2) the executive officer’s conviction of, or plea of guilty or nolo contendere to, any felony or of any other crime involving fraud, dishonesty or moral turpitude, (3) a determination by the board of directors that the executive officer has materially breached the employment agreement (other than during any period of disability) where such breach is not remedied within 10 days after written demand by the board of directors for substantial performance is actually received by the executive officer which specifically identifies the manner in which the board of directors believes the executive officer has so breached, or (4) the executive officer’s willful and continued failure to perform his reasonable and customary duties pursuant to his position with us which such failure is not remedied within 10 days after written demand by the board of directors for substantial performance is actually received by the executive officer which specifically identifies the nature of such failure. We also may terminate at any time an employment agreement for any other reason, in the sole discretion of our board of directors.

The executive may terminate his employment agreement for “good reason,” which means: (1) the assignment to the executive officer of duties and responsibilities that are materially inconsistent with those normally associated with his position excluding for this purpose an isolated, insubstantial and inadvertent action not taken in bad faith and which is remedied by us promptly after receipt of notice given by the executive officer, (2) a reduction in the executive officer’s base salary, (3) the executive officer’s removal from his position as stated in his employment agreement, other than for Cause or by death or disability, (4) the relocation of the executive officer’s principal place of business to a location 50 or more miles from its location as of the effective date of his employment agreement without the executive officer’s written consent, (5) a material breach by us of his employment agreement, which materially adversely affects the executive officer, and the breach is not cured within 20 days after the executive officer provides written notice to us which identifies in reasonable detail the nature of the breach, and (6) our failure to make any payment to the executive officer as required to be made under the terms of his employment agreement, and the breach is not cured within 20 days after the executive officer provides written notice to us which provides in reasonable detail the nature of the payment. Finally, the executive officer may terminate his employment agreement for any other reason, in his sole discretion.

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Termination due to Disability. If the executive officer’s employment is terminated due to his disability, the executive will be entitled to receive on the date of termination (1) all accrued but unpaid base salary, (2) a prorated amount of the executive officer’s base salary for accrued but unused vacation days, and (3) reimbursements for any reasonable and necessary business expenses incurred by the executive officer prior to the date of termination of his employment agreement in connection with his duties (such amounts are collectively referred to as accrued compensation and reimbursements) and (4) a payment equal to the executive officer’s base salary for 12 months.

Termination due to Death. If the executive officer’s employment is terminated due to his death, the executive, his beneficiary or his estate, as applicable, will be entitled to receive on the date of termination (1) accrued compensation and reimbursements, (2) a payment equal to the executive officer’s base salary for 12 months and (3) amounts payable in either cash or units on any phantom units outstanding at the time of the termination, including amounts payable on any unvested phantom units previously granted to the executive officer that will vest upon such termination.

Termination for Good Reason. If the executive terminates his employment for good reason (as defined above), we shall pay the executive officer (1) his accrued compensation and reimbursements plus (2) a payment equal to the greater of the executive’s base salary for 36 months and the remaining duration of the employment period.

Termination Without Cause. If the executive is terminated without cause during the term of the agreement, we shall pay the executive officer (1) his accrued compensation and reimbursements plus (2) a payment equal to the greater of the executive’s base salary for 36 months and the remaining duration of the employment period plus (3) amounts payable in either cash or units on any phantom units outstanding at the time of the termination, including amounts payable on any unvested phantom units previously granted to the executive officer that will vest upon such termination.

Termination for Cause or other than for Good Reason. Upon termination for cause or by the executive other than for good reason (each as defined above), the executive officer is only entitled to accrued compensation and reimbursements.

Termination upon a Change of Control.

Early Termination Option. In the event our initial public offering has not occurred prior to September 1, 2007, we can elect to terminate the executive officer’s employment agreement in its entirety. We will be responsible for reimbursing the executive officer his investment in us along with a payment of one (1) year base salary.

Sale of Us or Our Subsidiaries Prior to an initial public offering. In the event we are sold prior to the IPO, the chief executive officer and the chief financial officer shall be entitled to 2.0% and 1.0%, respectively, of the net proceeds of such sale. The net proceeds shall consist of any cash or unit consideration paid for our assets in excess of any outstanding debt burdening such assets. The executive officer is also entitled to all other consideration as set forth in his employment agreement.

Change of Control after an initial public offering. In the event a change of control occurs after our initial public offering (our initial public offering does not constitute a change of control), the executive officers will be entitled to a lump sum severance payment of three year’s base salary.

Estimated Payments to Executives. Assuming that (1) we had entered the employment agreements with the executive officers identified in “—Employment Agreements,” (2) we had granted those executives restricted units as indicated in “—Grants of Plan-Based Awards,” (3) each executive was terminated under each of the above circumstances on December 31, 2006 and (4) the value of each restricted unit is equal to $18.00 per unit for Messrs. Smith and Robert as of the date of the grant and $23.00 per unit for Mr. Pence, the midpoint of the range set forth on the cover page of this prospectus, payments and benefits owed to

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such executives would have an estimated value as set forth in the tables below. These amounts were negotiated between the employee and Nami and are equal to three years of base salary.

Scott W. Smith

	Cash Severance			Value of Accelerated Equity Awards
Without Cause or For Good Reason		$	600,000		$	4,320,000
Change in Control		$	600,000		$	4,320,000
Death		$	200,000		$	4,320,000
Disability		$	200,000		$	4,320,000
Non-renewal of Agreement		—			—
Other		—			—

Richard A. Robert

	Cash Severance			Value of Accelerated Equity Awards
Without Cause or For Good Reason		$	600,000		$	2,326,748
Change in Control		$	600,000		$	2,326,748
Death		$	200,000		$	2,326,748
Disability		$	200,000		$	2,326,748
Non-renewal of Agreement		—			—
Other		—			—

Britt Pence

	Cash Severance			Value of Accelerated Equity Awards
Without Cause or For Good Reason		$	600,000		$	1,207,561
Change in Control		$	600,000		$	1,207,561
Death		$	200,000		$	1,207,561
Disability		$	200,000		$	1,207,561
Non-renewal of Agreement		—			—
Other		—			—

Compensation of Directors

Each independent member of our board of directors will receive 5,000 Class B units or restricted common units upon becoming a director as well as compensation for attending meetings of the board of directors as well as committee meetings. The amount of compensation to be paid to the independent members of our board will be $7,500 per quarter and an additional $2,500 per quarter for the chairman of the audit committee. In addition, each independent member of our board will be reimbursed for 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 actions associated with being a member of our board to the extent permitted under Delaware law and as provided in our limited liability company agreement.

Employee Benefits

Our employees, including our executive officers, are entitled to various employee benefits. These benefits include the following: medical, dental and vision care plans; life, accidental death and dismemberment and disability insurance and paid time off.

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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth the beneficial ownership of units of our company immediately following the consummation of this offering, assuming no exercise of the underwriters’ option to purchase additional units, and the application of the related net proceeds and held by:

· each person who will then beneficially own 5% or more of the then outstanding units;

· each of the members of our board of directors;

· each named executive officer of our company; and

· all directors and executive officers as a group.

The amounts and percentage of units beneficially owned are reported on the basis of regulations of the SEC governing the determination of beneficial ownership of securities. Under the rules of the SEC, a person is deemed to be a “beneficial owner” of a security if that person has or shares “voting power,” which includes the power to vote or to direct the voting of such security, or “investment power,” which includes the power to dispose of or to direct the disposition of such security. A person is also deemed to be a beneficial owner of any securities of which that person has a right to acquire beneficial ownership within 60 days. Under these rules, more than one person may be deemed a beneficial owner of the same securities and a person may be deemed a beneficial owner of securities as to which he has no economic interest.

Except as indicated by footnote, the persons named in the table below have sole voting and investment power with respect to all units shown as beneficially owned by them, subject to community property laws where applicable.

Name of Beneficial Owner(1)	Units to be Beneficially Owned(2)		Percentage of Units to be Beneficially Owned
Nami Capital Partners, LLC(3)		1,171,430		10.7
Majeed S. Nami(5)		2,142,985		19.6
Majeed S. Nami Personal Endowment(4)		971,555		8.9
Majeed S. Nami Irrevocable Trust(4)		1,107,015		10.1
Scott W. Smith(6)		240,000		2.2
Richard A. Robert(6)		125,000		1.1
Britt Pence(6)		50,000		*
Thomas M. Blake		—		—
Lasse Wagene		—		—
W. Richard Anderson		5,000		*
Lehman Brothers MLP Opportunity Fund L.P.(7)		1,145,000		10.4
Third Point Partners LP(8)		556,470		5.1
Third Point Partners Qualified LP(8)		474,030		4.3
Daniel S. Loeb(8)		1,030,500		9.4
Third Point LLC(8)		1,030,500		9.4
BLRTQS Partners(9)		114,500		1.0
All directors and executive officers as a group (3 persons)		420,000		3.8

* Represents less than 1%.

(1) Unless otherwise indicated, the address for all beneficial owners in this table is c/o Vanguard Natural Resources, LLC, 7700 San Felipe, Suite 485, Houston, Texas 77063.

(2) There are an additional 40,000 Class B units available to be issued in the future.

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(3) Mr. Majeed S. Nami is the sole member of Nami Capital Partners, LLC.

(4) Ms. Ariana Nami, the daughter of Mr. Majeed S. Nami, is the trustee of the Majeed S. Nami Personal Endowment and the Majeed S. Nami Irrevocable Trust.

(5) Mr. Majeed S. Nami may be deemed to beneficially own the units held by Nami Capital Partners, LLC and the Majeed S. Nami Personal Endowment.

(6) Comprised of 240,000 Class B units that have been issued to Scott W. Smith, our President and Chief Executive Officer, 125,000 Class B units that have been issued to Richard A. Robert, our Executive Vice President and Chief Financial Officer and 50,000 Class B units that have been issued to Britt Pence, our Vice President of Engineering. The Class B units have substantially the same rights as the common units and, upon vesting, will become convertible into common units at the election of the holder.

(7) Lehman Brothers MLP Opportunity Fund L.P. can be contacted at the following address: 399 Park Avenue, Ninth Floor, New York, New York 10022.

(8) Third Point LLC, and Daniel S. Loeb in his capacity as the CEO of Third Point LLC, have voting and investment control over the shares held by Third Point Partners LP and Third Point Partners Qualified LP. Third Point LLC is the investment advisor for Third Point Partners LP and Third Point Partners Qualified L.P. Third Point LLC and Mr. Loeb disclaim beneficial ownership of all of such shares. Third Point LLC, Third Point Partners LP and Third Point Partners Qualified L.P. can be contacted at the following address: 390 Park Avenue, 18th Floor, New York, NY 10022.

(9) BLRTQS Partners, an affiliate of Third Point LLC, can be contacted at the following address: 4899 Montrose, Unit 1701, Houston, Texas 77006.

We will use any net proceeds from the exercise of the underwriters’ option to reduce borrowings under our reserve-based credit facility and any remaining net proceeds, if any, will be used for working capital and general corporate purposes.

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

In connection with the completion of this offering, we will adopt an ethics policy which will require that related party transactions be reviewed to ensure that they are fair and reasonable to us. This requirement is also contained in our limited liability company agreement. Whenever a conflict arises between Nami, on the one hand, and us or any other unitholder, on the other hand, our board of directors will resolve that conflict. We anticipate that our board of directors will submit for review and approval by our conflicts committee any material agreement that we enter into with Nami. See “Conflicts of Interest and Fiduciary Duties.”

On April 18, 2007 but effective January 5, 2007, we entered into several agreements with Vinland pursuant to which Vinland will operate all of our existing wells and coordinate our development drilling program and provide management services to us. The terms of each of these agreements were negotiated between us and Vinland. Because these agreements were negotiated prior to the adoption of the ethics policy discussed above, they were not approved by our Conflicts Committee as contemplated by that policy. Because of our related party affiliation with Vinland, these agreements, and future agreements with Vinland, may not contain the most competitive terms available to us. In addition, by purchasing a common unit, a unitholder will become bound by the provisions of our limited liability company agreement, including the related party agreements provided for therein, and a unitholder will be deemed to have consented to some actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable law.

Management Services Agreement

On April 18, 2007 but effective as of January 5, 2007, we entered into a management services agreement and participation agreement with Vinland, under which we believe that we will benefit from the substantial expertise of Vinland’s management in the Appalachian Basin. Under the management services agreement, Vinland advises and consults with us regarding all aspects of our production and development operations, and provides us with administrative support services as necessary for the operation of our business. We are dependent on Vinland for management of our operations and, pursuant to the management services agreement, we pay Vinland a monthly fee of $60 for each of our producing wells within the AMI in return for the administrative support services contemplated in the agreement and we also reimburse Vinland for the reasonable costs of any additional services it provides to us. When determining the amount of the monthly fee to pay Vinland, we considered Vinland’s costs to provide us with such services, how much it would cost for us to perform such services internally and how much a third party would charge us to perform such services. We believe that the $60 monthly fee reimburses Vinland for its actual costs for providing these services to us, and we believe that $60 is less than the amount it would cost for us to perform these services or to hire a third party to perform these services. Our board of directors may in the future cause us to hire additional personnel to supplement or replace some or all of the services provided by Vinland, as well as employ third-party service providers. If we were to take such actions, they could increase the overall costs of our operations. In addition, Vinland may, but does not have any obligation to, provide us with acquisition services under the management services agreement. While Vinland is not obligated to provide us with acquisition services, we expect that our mutually beneficial relationship will provide them with an incentive to grow our business by helping us to identify, evaluate and complete acquisitions that will be accretive to our distributable cash. As the management services agreement was executed on April 18, 2007 but was effective as of January 5, 2007, we expect to have a post-closing adjustment to account for the period of operations occurring after January 5, 2007 and before April 18, 2007. During the six months ended June 30, 2007, we paid Vinland $0.3 million pursuant to the management services agreement.

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Participation Agreement

Pursuant to our participation agreement with Vinland, Vinland generally has control over our drilling program and the sole right to determine which wells are drilled until January 5, 2011. During this period, we will meet with Vinland on a quarterly basis to review Vinland’s proposal to drill not less than 25 nor more than 40 gross wells, in which we will own an approximate 40% working interest, in any quarter. Up to 20% of the proposed wells may be carried over and added to the wells to be drilled in the subsequent quarter, provided that Vinland is required to drill at least 100 gross wells per calendar year. If Vinland proposes the drilling of less than 25 gross wells in any quarter we have the right to direct the drilling of up to a total of 14 wells, in which we will own an approximate 100% working interest, in a given quarterly period. Based on our production rate at March 31, 2007 and June 30, 2007, we believe we need to drill approximately 130 gross (52 net) wells per year to maintain our production at current levels. By contrast, based upon a sensitivity analysis prepared by NSAI, if Vinland only drills its minimum commitment of 100 gross wells per calendar year, our total production is expected to decline by an average of approximately 2.7% per year for the three-year period beginning March 31, 2007. If Vinland drills its minimum commitment, we do not have the ability to drill our own additional wells in the AMI. If either party elects not to participate in the drilling of the proposed wells or future operations with respect to drilled wells, such party forfeits all right, title and interest in the natural gas and oil production that may be produced from such wells. The participation agreement will remain in place until January 5, 2012 and shall continue thereafter on a year to year basis until such time as either party elects to terminate the agreement. The obligations of the parties with respect to the drilling program described above will expire on January 5, 2011, after which we each will have the right to propose the drilling of wells within the AMI and thereby offer participation in such proposed drilling to the other party and if either party elects not to participate in such proposed drilling operation or future operations with respect to drilled wells, such party forfeits all right, title and interest in the natural gas and oil production that may be produced from such wells. As the participation agreement was executed on April 18, 2007 but was effective as of January 5, 2007, we expect to have a post-closing adjustment to account for the period of operations occurring after January 5, 2007 and before April 18, 2007. During the six months ended June 30, 2007, we paid Vinland $6.1 million pursuant to the participation agreement.

Gathering and Compression Agreement

On April 18, 2007 but effective as of January 5, 2007, we entered into gathering and compression agreements with an affiliate of Vinland, Vinland Energy Gathering, LLC, or Vinland Gathering. Under these agreements, Vinland Gathering will gather, compress, deliver and provide the services necessary for us to market our natural gas production in the area of mutual interest. Vinland Gathering will deliver our natural gas production to certain designated interconnects with third-party transporters. We pay Vinland Gathering a fee of $0.25 per Mcf, plus our proportionate share of fuel and line loss for producing wells as of January 5, 2007. For all wells drilled after January 5, 2007 we pay Vinland Gathering a fee of $0.55 per Mcf, plus our proportionate share of fuel and line loss. When determining the fee of $0.25 per Mcf, we considered Vinland Gathering’s costs to provide us with such services and how much a third party would charge us to perform such services. We determined that a fee of $0.25 per Mcf reimburses Vinland Gathering for its actual costs for providing these services to us and is less than the amount that a third party would charge us to perform these services. When determining the fee of $0.55 per Mcf, we considered the incremental capital costs that Vinland Gathering would incur as a result of connecting new wells to the system, and we adjusted the fee accordingly. The gathering and compression rates will increase by 11% on January 1, 2011, and shall be adjusted annually thereafter based on a published wage index adjustment factor. As the gathering and compression agreements were executed on April 18, 2007 but were effective as of January 5, 2007, we expect to have a post-closing adjustment to account for the period of operations occurring after January 5, 2007 and before April 18, 2007. During the six months ended

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June 30, 2007, we paid Vinland Gathering $0.7 million pursuant to the gathering and compression agreement.

Vinland Gathering gathers 100% of our current production and we expect Vinland Gathering will gather 100% of the wells we expect to drill in 2007. Vinland Gathering’s network of natural gas gathering systems permits us to transport production from our wells with fewer interruptions and also minimizes any delays associated with a non-affiliated gathering company extending its lines to our wells. Our relationship with Vinland and Vinland Gathering enables us to realize:

· faster connection of newly drilled wells to the existing system;

· control compression costs and fuel use;

· control the monthly nominations on the receiving pipelines to prevent imbalances and penalties; and

· closely track sales volumes and receipts to assure all production values are realized.

Following this offering, we will also assume certain transportation agreements that Vinland currently has with Delta Natural Gas with respect to volumes of gas produced in Kentucky. Delta receives gas from various interconnects with Vinland and redelivers said volumes to Columbia Gas Transmission. We will pay Delta $0.26 per MMBtu plus a fuel charge equal to 2% of volume for this transportation service.

In addition, following this offering, we will assume 7,000 MMBtu/day of firm transportation that Vinland currently has on the Columbia Gas Transmission system. We will pay Columbia Gas $0.22 per MMBtu plus a fuel charge equal to 2% of volume for this firm transportation right. This volume is approximately 44% of our total 2007 estimated production.

Operating Agreements and Well Services Agreements

All wells drilled under the participation agreement will be subject to an operating agreement and accompanying accounting procedures whereby Vinland is the operator of such wells. Failure of any working interest owner to participate in future operations will result in forfeiture of its interest in the applicable well. As the operating agreements were executed on April 18, 2007 but were effective as of January 5, 2007, we expect to have a post-closing adjustment to account for the period of operations occurring after January 5, 2007 and before April 18, 2007. All proved developed producing wells that are owned by us will be operated by Vinland pursuant to a well services agreement and accompanying accounting procedures. Vinland will contract for substantially all services to be provided under this agreement with third-party contractors. Most of these third-party contracts are currently in place. As the well services agreements were executed on April 18, 2007 but were effective as of January 5, 2007, we expect to have a post-closing adjustment to account for the period of operations occurring after January 5, 2007 and before April 18, 2007. During the six months ended June 30, 2007, we paid Vinland $0.4 million pursuant to the operating agreements and well services agreements.

Indemnity Agreement

In connection with the Nami Restructuring Plan, we entered into an indemnity agreement with Nami Resources and Vinland wherein Nami Resources and Vinland have agreed to indemnify one of our subsidiaries, Trust Energy Company, LLC, for all liabilities, judgments and damages that may arise in connection with certain litigation that Nami Resources is a party to, Asher Land and Mineral, Ltd. v. Nami Resources Company, LLC, Bell Circuit Court, Civil Action No. 06-CI-00566. We recently amended the indemnity agreement to add us and Vanguard Natural Gas, LLC as parties to the indemnity agreement. In addition, Nami Resources and Vinland have agreed to provide for the defense of any such claims against

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us. The indemnities agreed to by Nami Resources and Vinland in this agreement will remain in place until the resolution of the Asher litigation. Please read “Business—Operations—Legal Proceedings.”

Revenue Payment Agreement

In connection with the Nami Restructuring Plan, we received a contract right to receive approximately 99% of the net proceeds, after deducting royalties paid to other parties, severance taxes, third-party transportation costs, costs incurred in the operation of wells and overhead costs, from the sale of production from certain producing oil and gas wells located within the Asher lease, which accounted for approximately 5% of our pro forma estimated proved reserves as of March 31, 2007. During the six months ended June 30, 2007, we have received revenue payments of $1.0 million pursuant to this agreement.

Registration Rights Agreement

We entered into a registration rights agreement with the Private Investors. In the registration rights agreement we agreed, upon completion of this offering, to register the units issuable to the Private Investors. Specifically, we agreed:

· to file with the SEC, within 90 days after the closing date of this offering, a registration statement (a “shelf registration statement”);

· to use our commercially reasonable efforts to cause the shelf registration statement to become effective under the Securities Act within 180 days after the closing of this offering;

· to continuously maintain the effectiveness of the shelf registration statement under the Securities Act until the units covered by the shelf registration statement have been sold, transferred or otherwise disposed of:

· pursuant to the shelf, or any other, registration statement;

· pursuant to Rule 144 under the Securities Act;

· to us or any of our subsidiaries; or

· in a private transaction in which the transferor’s rights under the registration rights agreement are not assigned to the transferee of the units.

We, our management, Nami and certain of his affiliates and related persons, including the members of the board of directors and executive officers of our company and the Private Investors, have agreed not to sell any units for a period of 180 days from the date of this prospectus. Please read “Underwriting” for a description of these lock-up provisions.

Omnibus Agreement

Upon the closing of this offering, we will enter into the omnibus agreement with Nami. Under the omnibus agreement, Nami will indemnify us after the closing of this offering against certain liabilities relating to:

· until 60 days after the applicable statute of limitations, any of our income tax liabilities, or any income tax liability attributable to the operation of our properties or those of any of our subsidiaries, including taxes resulting from the consummation of our formation or the Nami Restructuring Plan, in each case relating to periods prior to and including the closing of our private equity offering in April 2007;

· for a period of one year after the closing of our private equity offering in April 2007, the failure to have all necessary consents and governmental permits where such failure renders us unable to use

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and operate our assets in substantially the same manner in which they were used and operated immediately prior to the closing of our private equity offering in April 2007, provided that (i) the aggregate amount payable to us pursuant to this bullet point does not exceed $1,000,000 and (ii) amounts are only payable to us pursuant to this bullet point after liabilities relating to this bullet point have exceeded $250,000;

· for a period of three years after the closing of our private equity offering in April 2007, our failure to have good and defeasible title to our assets as required to operate our assets in the manner described in this prospectus, provided that (i) the aggregate amount payable to us pursuant to this bullet point does not exceed (A) $15,000,000 for claims relating to this bullet point made before the end of the first year, (B) $12,500,000 for claims relating to this bullet point made before the end of the second year and (C) $10,000,000 for claims relating to this bullet point made before the end of the third year and (ii) amounts are only payable to us pursuant to this bullet point after liabilities relating to this bullet point have exceeded $250,000;

· for a period of three years after the closing of our private equity offering in April 2007, environmental liabilities relating to periods prior to the closing of our private equity offering in April 2007, including (i) any violation or correction of violation of environmental laws associated with our assets, where a correction of violation would include assessment, investigation, monitoring, remediation, or other similar action and (ii) any event, omission or condition associated with the ownership of our assets (including presence of hazardous materials), including (A) the cost and expense of any assessment, investigation, monitoring, remediation or other similar action and (B) the cost and expense of any environmental or toxic tort litigation, provided that (i) the aggregate amount payable to us pursuant to this bullet point does not exceed $1,500,000 and (ii) amounts are only payable to us pursuant to this bullet point after liabilities relating to this bullet point have exceeded $250,000; and

· until April 18, 2009, all assets and liabilities we conveyed in the Nami Restructuring Plan to Vinland or its affiliates, provided that the aggregate amount payable to us pursuant to this bullet point does not exceed $250,000.

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CONFLICTS OF INTEREST AND FIDUCIARY DUTIES

Conflicts of Interest

Nami and his affiliates and related persons will own approximately 29.7% of our outstanding common units after this offering. In addition, on April 18, 2007 but effective January 5, 2007, we entered into various agreements with Vinland, an affiliate of Nami, under which we rely on Vinland to operate all of our existing producing wells and to coordinate our drilling program. We also rely on Vinland to provide us with administrative support services as are necessary for the operation of our business. Please read “Certain Relationships and Related Party Transactions.” Conflicts of interest exist and may arise in the future as a result of the relationships between us and our unaffiliated unitholders and our board of directors and executive officers and Vinland and its affiliates. These potential conflicts may relate to the divergent interests of these parties.

Whenever a conflict arises between Vinland and its affiliates, on the one hand, and us or any other unitholder, on the other hand, our board of directors will resolve that conflict. Our limited liability company agreement limits the remedies available to unitholders in the event a unitholder has a claim relating to conflicts of interest.

No breach of obligation will occur under our limited liability company agreement in respect of any conflict of interest if the resolution of the conflict is:

· approved by the conflicts committee of our board of directors, although our board of directors is not obligated to seek such approval;

· approved by the vote of a majority of the outstanding units although our board of directors is not obligated to seek such approval;

· on terms no less favorable to us than those generally provided to or available from unaffiliated 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.

We anticipate that our board of directors will submit for review and approval by our conflicts committee any acquisitions of properties or other assets that we propose to acquire from Vinland or any of its affiliates.

If our board of directors does not seek approval from the conflicts committee of our board of directors and our board 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, including board members affected by the conflict of interest, acted in good faith, and in any proceeding brought by or on behalf of any member or us, 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 limited liability company agreement, our board of directors or its conflicts committee may consider any factors in good faith when resolving a conflict. When our limited liability company agreement requires someone to act in good faith, it requires that person to reasonably believe that he is acting in our best interests, unless the context otherwise requires.

Conflicts of interest could arise in the situations described below, among others.

Vinland and its affiliates may compete with us.

None of Vinland or any of its affiliates is restricted from competing with us. Vinland and its affiliates may acquire, invest in or dispose of exploration and production or other assets, including those that might

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be in direct competition with us. For example, Vinland owns other oil and natural gas properties in the Appalachian Basin that were not retained by us in the Nami Restructing Plan or otherwise. Except as otherwise provided under the participation agreement and management services agreement, Vinland is not required to consider our interests.

Mr. Nami, who together with certain of his affiliates and related persons, will own approximately 29.7% of our outstanding common units after this offering, and certain members of our board of directors who are officers or directors of Vinland may have conflicts of interest with us. The ultimate resolution of these conflicts of interest may result in favoring the interests of these other parties over yours and may be to our detriment. Our limited liability company agreement limits the remedies available to you in the event you have a claim relating to conflicts of interest.

· we rely on Vinland to operate and develop our properties;

· we depend on Vinland to gather, compress, deliver and provide services necessary for us to market our natural gas production;

· Nami and his affiliates, including Vinland, and the Private Investors, are not prohibited from investing or engaging in other businesses or activities that compete with us.

If in resolving conflicts of interest that exist or arise in the future our board of directors or officers, as the case may be, satisfy the applicable standards set forth in our limited liability company agreement for resolving conflicts of interest, you will not be able to assert that such resolution constituted a breach of fiduciary duty owed to us or to you by our board of directors and officers.

Unitholders will have no right to enforce obligations of Vinland and its affiliates under agreements with us.

Any agreements, including the management services agreement, between us, on the one hand, and Vinland and its affiliates, on the other hand, will not grant to our unitholders any right to enforce the obligations of Vinland and its affiliates in our favor.

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Contracts between us, on the one hand, and Vinland and its affiliates, on the other, will not be the result of arm’s-length negotiations.

Neither our limited liability company agreement nor any of the other contracts or arrangements, including our participation agreement and management services agreement, between us and Vinland and its affiliates are or will be the result of arm’s-length negotiations.

Fiduciary Duties

Our limited liability company agreement provides that our business and affairs shall be managed under the direction of our board of directors, which shall have the power to appoint our officers. Our limited liability company agreement further provides that the authority and function of our board of directors and officers shall be identical to the authority and functions of a board of directors and officers of a corporation organized under the Delaware General Corporation Law, or DGCL. Finally, our limited liability company agreement provides that except as specifically provided therein, the fiduciary duties and obligations owed to our limited liability company and to our members shall be the same as the respective duties and obligations owed by officers and directors of a corporation organized under the DGCL to their corporation and stockholders, respectively. Our limited liability company agreement permits affiliates of our directors to invest or engage in other businesses or activities that compete with us. In addition, our limited liability company agreement establishes a conflicts committee of our board of directors, consisting solely of independent directors, which will upon referral from our board of directors be authorized to review transactions involving potential conflicts of interest. If the conflicts committee approves such a transaction, or if a transaction is on terms generally available from third parties or an action is taken that is fair and reasonable to the company, you will not be able to assert that such approval constituted a breach of fiduciary duties owed to you by our directors and officers.

We are unlike publicly traded partnerships whose business and affairs are managed by a general partner with fiduciary duties to the partnership. While Vinland will provide administrative, operational and other services to us pursuant to the participation agreement and management services agreement, subject to the oversight of our board of directors, we have no general partner with fiduciary duties to us. Vinland’s duties to us are contractual in nature and arise under the agreements described under “Certain Relationships and Related Party Transactions.” As a consequence, Vinland and its affiliates do not will owe us a fiduciary duty similar to that owed by a general partner to its limited partners.

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DESCRIPTION OF THE UNITS

The Units

The units represent limited liability company interests in us. The holders of units are entitled to participate in distributions and exercise the rights or privileges available to unitholders under our limited liability company agreement. For a description of the relative rights and preferences of holders of units in and to distributions, please read this section and “Cash Distribution Policy and Restrictions on Distributions.” For a description of the rights and privileges of unitholders under our limited liability company agreement, including voting rights, please read “The Limited Liability Company Agreement.”

Transfer Agent and Registrar

Computershare will serve as registrar and transfer agent for the units. We pay all fees charged by the transfer agent for transfers of units, except the following fees that will 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 holder of a unit; and

· other similar fees or charges.

There will be no charge to holders for disbursements of our cash distributions. We will indemnify the transfer agent, its agents and each of their shareholders, 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.

The transfer agent may at any time 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, we are authorized to act as the transfer agent and registrar until a successor is appointed.

Transfer of Units

By transfer of units in accordance with our limited liability company agreement, each transferee of units shall be admitted as a unitholder with respect to the units transferred when such transfer and admission is reflected on our books and records. Additionally, each transferee of units:

· becomes the record holder of the units;

· automatically agrees to be bound by the terms and conditions of, and is deemed to have executed our limited liability company agreement;

· represents that the transferee has the capacity, power and authority to enter into the limited liability company agreement;

· grants powers of attorney to our officers and any liquidator of our company as specified in the limited liability company agreement; and

· makes the consents and waivers contained in our limited liability company agreement.

An assignee will become a unitholder of our company for the transferred units upon the recording of the name of the assignee on our books and records.

Until a unit has been transferred on our books, we and the transfer agent, notwithstanding any notice to the contrary, 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 LIMITED LIABILITY COMPANY AGREEMENT

The following is a summary of the material provisions of our limited liability company agreement. The form of the limited liability company agreement is included in this prospectus as Appendix A. We will provide prospective investors with a copy of the form of this agreement upon request at no charge.

We summarize the following provisions of our limited liability company agreement elsewhere in this prospectus:

· with regard to distributions of available cash, please read “How We Make Cash Distributions.”

· with regard to the transfer of units, please read “Description of the Units—Transfer of Units.”

· with regard to the election of members of our board of directors, please read “Management—Our Board of Directors.”

· with regard to allocations of taxable income and taxable loss, please read “Material Tax Consequences.”

Organization

Our company was formed in October 2006 and will remain in existence until dissolved in accordance with our limited liability company agreement.

Purpose

Under our limited liability company agreement, we are permitted to engage, directly or indirectly, in any activity that our board of directors approves and that a limited liability company organized under Delaware law lawfully may conduct; provided, that our board of directors shall not cause us to engage, directly or indirectly, in any business activities that it 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 board of directors has the ability to cause us and our operating subsidiaries to engage in activities other than the exploitation, development and production of natural gas reserves, our board of directors has no current plans to do so. Our board of directors is authorized in general to perform all acts it deems to be necessary or appropriate to carry out our purposes and to conduct our business.

Fiduciary Duties

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Agreement to be Bound by Limited Liability Company Agreement; Power of Attorney

By purchasing a unit in us, you will be admitted as a unitholder of our company and will be deemed to have agreed to be bound by the terms of our limited liability company agreement. Pursuant to this agreement, each unitholder and each person who acquires a unit from a unitholder grants to our board of directors (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 board of directors the authority to make certain amendments to, and to make consents and waivers under and in accordance with, our limited liability company agreement.

Capital Contributions

Unitholders are not obligated to make additional capital contributions, except as described below under “—Limited Liability.”

Limited Liability

Unlawful Distributions. The Delaware Act provides that a unitholder 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 company for the amount of the distribution for three years. Under the Delaware Act, a limited liability company may not make a distribution to a unitholder if, after the distribution, all liabilities of the company, other than liabilities to unitholders on account of their membership interests and liabilities for which the recourse of creditors is limited to specific property of the company, would exceed the fair value of the assets of the company. For the purpose of determining the fair value of the assets of a company, 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 company only to the extent that the fair value of that property exceeds the nonrecourse liability. Under the Delaware Act, an assignee who becomes a substituted unitholder of a company is liable for the obligations of his assignor to make contributions to the company, except the assignee is not obligated for liabilities unknown to him at the time he became a unitholder and that could not be ascertained from the limited liability company agreement.

Failure to Comply with the Limited Liability Provisions of Jurisdictions in Which We Do Business. Our subsidiaries will initially conduct business only in the States of Kentucky and Tennessee. We may decide to conduct business in other states, and maintenance of limited liability for us, as a member of our operating subsidiaries, may require compliance with legal requirements in the jurisdictions in which the operating subsidiaries conduct business, including qualifying our subsidiaries to do business there. Limitations on the liability of unitholders for the obligations of a limited liability company have not been clearly established in many jurisdictions. We will operate in a manner that our board of directors considers reasonable and necessary or appropriate to preserve the limited liability of our unitholders.

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Voting Rights

The following matters require the unitholder vote specified below:

Election of members of the board of directors		Following our initial public offering we will have three directors. Our limited liability company agreement provides that we will have a board of not less than three members. Holders of our units, voting together as a single class, will elect our directors. Please read “—Election of Members of Our Board of Directors.”
Issuance of additional units		No approval right.
Amendment of the limited liability company agreement		Certain amendments may be made by our board of directors without the approval of the unitholders. Other amendments generally require the approval of a unit majority. Please read “—Amendment of Our Limited Liability Company Agreement.”
Merger of our company or the sale of all or substantially all of our assets		Unit majority. Please read “—Merger, Sale or Other Disposition of Assets.”
Dissolution of our company		Unit majority. Please read “—Termination and Dissolution.”

Matters requiring the approval of a “unit majority” require the approval of a majority of the outstanding units.

Issuance of Additional Securities

Our limited liability company agreement authorizes us to issue an unlimited number of additional securities and authorizes us to buy securities for the consideration and on the terms and conditions determined by our board of directors without the approval of the unitholders.

It is possible that we will fund acquisitions through the issuance of additional units or other equity securities. Holders of any additional units we issue will be entitled to share equally with the then-existing holders of units in our distributions of available cash. In addition, the issuance of additional units or other equity securities may dilute the value of the interests of the then-existing holders of units in our net assets.

In accordance with Delaware law and the provisions of our limited liability company agreement, we may also issue additional securities that, as determined by our board of directors, may have special voting or other rights to which the units are not entitled.

The holders of units will not have preemptive or preferential rights to acquire additional units or other securities.

Election of Members of Our Board of Directors

At our first annual meeting of unitholders following this offering, members of our board of directors will be elected by our unitholders and will be subject to re-election on an annual basis at our annual meeting of unitholders.

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Removal of Members of Our Board of Directors

Any director may be removed, with or without cause, by the holders of a majority of the outstanding units then entitled to vote at an election of directors.

Amendment of Our Limited Liability Company Agreement

General. Amendments to our limited liability company agreement may be proposed only by or with the consent of our board of directors. To adopt a proposed amendment, other than the amendments discussed below, our board of directors is required to seek written approval of the holders of the number of units required to approve the amendment or call a meeting of our unitholders 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 unitholder without its consent, unless approved by at least a majority of the type or class of member interests so affected;

· provide that we are not dissolved upon an election to dissolve our company by our board of directors that is approved by a unit majority;

· change the term of existence of our company; or

· give any person the right to dissolve our company other than our board of directors’ right to dissolve our company with the approval of a unit majority.

The provision of our limited liability company agreement preventing the amendments having the effects described in any of the clauses above can be amended upon the approval of the holders of at least 75% of the outstanding units, voting together as a single class.

No Unitholder Approval. Our board of directors may generally make amendments to our limited liability company agreement without the approval of any unitholder 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 members in accordance with our limited liability company agreement;

· a change that our board of directors determines to be necessary or appropriate for us to qualify or continue our qualification as a company in which our members have limited liability under the laws of any state or to ensure that neither we, our operating subsidiaries 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, members of our board, or our officers, agents or trustees from in any manner being subjected to the provisions of the Investment Company Act of 1940, the Investment Advisors 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;

· an amendment that our board of directors determines to be necessary or appropriate for the authorization of additional securities or rights to acquire securities;

· any amendment expressly permitted in our limited liability company agreement to be made by our board of directors acting alone;

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· an amendment effected, necessitated or contemplated by a merger agreement that has been approved under the terms of our limited liability company agreement;

· any amendment that our board of directors 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 limited liability company agreement;

· a change in our fiscal year or taxable year and related changes;

· a merger, conversion or conveyance effected in accordance with the limited liability company agreement; and

· any other amendments substantially similar to any of the matters described in the clauses above.

In addition, our board of directors may make amendments to our limited liability company agreement without the approval of any unitholder or assignee if our board of directors determines that those amendments:

· do not adversely affect the unitholders (including any particular class of unitholders as compared to other classes of unitholders) in any material respect;

· 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 units or to comply with any rule, regulation, guideline or requirement of any securities exchange on which the units are or will be listed for trading, compliance with any of which our board of directors deems to be in the best interests of us and our unitholders;

· are necessary or appropriate for any action taken by our board of directors relating to splits or combinations of units under the provisions of our limited liability company agreement; or

· are required to effect the intent expressed in this prospectus or the intent of the provisions of our limited liability company agreement or are otherwise contemplated by our limited liability company agreement.

Opinion of Counsel and Unitholder Approval. Our board of directors will not be required to obtain an opinion of counsel that an amendment will not result in a loss of limited liability to our unitholders or result in our being treated as an entity for federal income tax purposes if one of the amendments described above under “—No Unitholder Approval” should occur. No other amendments to our limited liability company agreement will become effective without the approval of holders of at least 90% of the units unless we obtain an opinion of counsel to the effect that the amendment will not affect the limited liability under applicable law of any unitholder of our company.

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 unitholders whose aggregate outstanding units constitute not less than the voting requirement sought to be reduced.

Merger, Sale or Other Disposition of Assets

Our board of directors is generally prohibited, 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,

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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, provided that our board of directors may mortgage, pledge, hypothecate or grant a security interest in all or substantially all of our assets without that approval. Our board of directors may also sell all or substantially all of our assets under a foreclosure or other realization upon the encumbrances above without that approval.

If the conditions specified in the limited liability company agreement are satisfied, our board of directors may merge our company or any of its subsidiaries into, or convey all of our assets to, a newly-formed entity if the sole purpose of that merger or conveyance is to effect a mere change in our legal form into another limited liability entity. The unitholders are not entitled to dissenters’ rights of appraisal under the limited liability company agreement or applicable Delaware law in the event of a merger or consolidation, a sale of all or substantially all of our assets or any other transaction or event.

Termination and Dissolution

We will continue as a company until terminated under our limited liability company agreement. We will dissolve upon: (1) the election of our board of directors to dissolve us, if approved by the holders of a unit majority; (2) the sale, exchange or other disposition of all or substantially all of the assets and properties of our company and our subsidiaries; or (3) the entry of a decree of judicial dissolution of our company.

Liquidation and Distribution of Proceeds

Upon our dissolution, the liquidator authorized to wind up our affairs will, acting with all of the powers of our board of directors that the liquidator deems necessary or desirable in its judgment, liquidate our assets and apply the proceeds of the liquidation as provided in “How We 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 unitholders in kind if it determines that a sale would be impractical or would cause undue loss to our unitholders.

Anti-Takeover Provisions

Our limited liability company agreement contains specific provisions that are intended to discourage a person or group from attempting to take control of our company without the approval of our board of directors. Specifically, our limited liability company agreement provides that we will elect to have Section 203 of the DGCL apply to transactions in which an interested common unitholder (as described below) seeks to enter into a merger or business combination with us. Under this provision, such a holder will not be permitted to enter into a merger or business combination with us unless:

· prior to such time, our board of directors approved either the business combination or the transaction that resulted in the common unitholder’s becoming an interested common unitholder;

· upon consummation of the transaction that resulted in the common unitholder becoming an interested common unitholder, the interested common unitholder owned at least 85% of our outstanding common units at the time the transaction commenced, excluding for purposes of determining the number of common units outstanding those common units owned:

· by persons who are directors and also officers; and

· by employee common unit plans in which employee participants do not have the right to determine confidentially whether common units held subject to the plan will be tendered in a tender or exchange offer; or

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· at or subsequent to such time the business combination is approved by our board of directors and authorized at an annual or special meeting of our common unitholders, and not by written consent, by the affirmative vote of the holders of at least 66 2/3% of our outstanding voting common units that are not owned by the interested common unitholder.

Section 203 defines “business combination” to include:

· any merger or consolidation involving the company and the interested common unitholder;

· any sale, transfer, pledge or other disposition of 10% or more of the assets of the company involving the interested common unitholder;

· subject to certain exceptions, any transaction that results in the issuance or transfer by the company of any common units of the company to the interested common unitholder;

· any transaction involving the company that has the effect of increasing the proportionate share of the units of any class or series of the company beneficially owned by the interested common unitholder; or

· the receipt by the interested common unitholder of the benefit of any loans, advances, guarantees, pledges or other financial benefits provided by or through the company.

In general, by reference to Section 203, an “interested common unitholder” is any person or entity that beneficially owns (or within three years did own) 15% or more of the outstanding common units of the company and any entity or person affiliated with or controlling or controlled by such entity or person.

The existence of this provision would be expected to have an anti-takeover effect with respect to transactions not approved in advance by our board of directors, including discouraging attempts that might result in a premium over the market price for common units held by common unitholders.

Our limited liability agreement also restricts the voting rights of common unitholders by providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than persons who acquire such units with the prior approval of the board of directors, cannot vote on any matter.

Limited Call Right

If at any time any person owns more than 90% of the then-issued and outstanding membership interests of any class, such person 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 remaining membership interests of the class held by unaffiliated persons as of a record date to be selected by our management, on at least 10 but not more than 60 days’ notice. The unitholders are not entitled to dissenters’ rights of appraisal under the limited liability company agreement or applicable Delaware law if this limited call right is exercised. The purchase price in the event of this purchase is the greater of:

· the highest cash price paid by such person for any membership interests of the class purchased within the 90 days preceding the date on which such person first mails notice of its election to purchase those membership interests; or

· the closing market price as of the date three days before the date the notice is mailed.

As a result of this limited call right, a holder of membership interests in our company may have his membership interests purchased at an undesirable time or price. Please read “Risk Factors—Risks Related to Our Structure.” The tax consequences to a unitholder of the exercise of this call right are the same as a sale by that unitholder of his units in the market. Please read “Material Tax Consequences—Disposition of Units.”

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Meetings; Voting

All notices of meetings of unitholders shall be sent or otherwise given in accordance with Section 11.4 of our limited liability company agreement not less than 10 nor more than 60 days before the date of the meeting. The notice shall specify the place, date and hour of the meeting and (i) in the case of a special meeting, the general nature of the business to be transacted (no business other than that specified in the notice may be transacted) or (ii) in the case of the annual meeting, those matters which the board of directors, at the time of giving the notice, intends to present for action by the unitholders (but any proper matter may be presented at the meeting for such action). The notice of any meeting at which directors are to be elected shall include the name of any nominee or nominees who, at the time of the notice, the board of directors intends to present for election. Any previously scheduled meeting of the unitholders may be postponed, and any special meeting of the unitholders may be cancelled, by resolution of the board of directors upon public notice given prior to the date previously scheduled for such meeting of unitholders.

Units that are owned by an assignee who is a record holder, but who has not yet been admitted as a unitholder, shall be voted at the written direction of the record holder by a proxy designated by our board of directors. Absent direction of this kind, the units will not be voted, except that units held by us on behalf of non-citizen assignees shall be voted in the same ratios as the votes of unitholders on other units are cast.

Any action required or permitted to be taken by our unitholders must be effected at a duly called annual or special meeting of unitholders and may not be effected by any consent in writing by such unitholders.

Meetings of the unitholders may only be called by a majority of our board of directors. 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 shall 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 shall be the greater percentage.

Each record holder of a unit has a vote according to his percentage interest in us, although additional units having special voting rights could be issued. Please read “—Issuance of Additional Securities.” Units held in nominee or street name accounts 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 its nominee provides otherwise.

Any notice, demand, request, report or proxy material required or permitted to be given or made to record holders of units under our limited liability company agreement will be delivered to the record holder by us or by the transfer agent.

Non-Citizen Assignees; Redemption

If we or any of our subsidiaries are or become subject to federal, state or local laws or regulations that, in the reasonable determination of our board of directors, create a substantial risk of cancellation or forfeiture of any property that we have an interest in because of the nationality, citizenship or other related status of any unitholder or assignee, we may redeem, upon 30 days’ advance notice, the units held by the unitholder or assignee at their current market price. To avoid any cancellation or forfeiture, our board of directors may require each unitholder or assignee to furnish information about his nationality, citizenship or related status. If a unitholder or assignee fails to furnish information about his nationality, citizenship or other related status within 30 days after a request for the information or our board of directors determines after receipt of the information that the unitholder or assignee is not an eligible citizen, the unitholder or assignee may be treated as a non-citizen assignee. In addition to other limitations on the rights of an assignee who is not a substituted unitholder, a non-citizen assignee does not have the right to direct the voting of his units and may not receive distributions in kind upon our liquidation.

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Indemnification

Under our limited liability company agreement and subject to specified limitations, we will indemnify to the fullest extent permitted by law, from and against all losses, claims, damages or similar events any director or officer, or while serving as a director or officer, any person who is or was serving as a tax matters member or as a director, officer, tax matters member, employee, partner, manager, fiduciary or trustee of any or our affiliates. Additionally, we shall indemnify to the fullest extent permitted by law, from and against all losses, claims, damages or similar events any person is or was an employee (other than an officer) or agent of our company.

Any indemnification under our limited liability company agreement will only be out of our assets. We are authorized to 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 limited liability company agreement.

Books and Reports

We are 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 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 unitholders 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.

Right To Inspect Our Books and Records

Our limited liability company agreement provides that a unitholder can, for a purpose reasonably related to his interest as a unitholder, upon reasonable demand and at his own expense, have furnished to him:

· a current list of the name and last known address of each unitholder;

· 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 unitholder and the date on which each became a unitholder;

· copies of our limited liability company agreement, the certificate of formation of the company, 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.

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Our board of directors may, and intends to, keep confidential from our unitholders information that it believes to be in the nature of trade secrets or other information, the disclosure of which our board of directors believes in good faith is not in our best interests, information that could damage our company or our business, or information that we are required by law or by agreements with a third-party to keep confidential.

Registration Rights

Nami and his affiliates are entitled under our limited liability company agreement to registration rights with respect to the units acquired by them in connection with the private placement. Please read “Units Eligible for Future Sale.”

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UNITS ELIGIBLE FOR FUTURE SALE

After the sale of the units offered by this prospectus, and assuming that the underwriters’ option to purchase additional units is not exercised, Nami, certain members of our management and the Private Investors will hold, directly and indirectly, an aggregate of 6,000,000 units. The sale of these units could have an adverse impact on the price of the units or on any trading market that may develop.

The units sold in this offering will generally be freely transferable without restriction or further registration under the Securities Act, except that any units held 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 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 units for are least two years, would be entitled to sell units under Rule 144 without regard to the public information requirements, volume limitations, manner of sale provisions and notice requirements of Rule 144.

Our limited liability company agreement provides that we may issue an unlimited number of limited liability company interests of any type without a vote of the unitholders. Our limited liability company agreement does not restrict our ability to issue equity securities ranking junior to the units at any time. Any issuance of additional 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, units then outstanding. Please read “The Limited Liability Company Agreement—Issuance of Additional Securities.”

Pursuant to our limited liability company agreement, Nami and his affiliates have the right to cause us to register under the Securities Act and applicable state securities laws the offer and sale of any units that they hold. Subject to the terms and conditions of our limited liability company agreement, these registration rights allow Nami and/or certain of his permitted transferees to require registration of any of their units and any units held by non-affiliated equity investors. In addition, Nami, non-affiliated equity investors and/or their respective permitted transferees may include any of their units in a registration by us of other units, including units offered by us or by any unitholder. 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 applicable 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 commissions. Except as described below, Nami and non-affiliated equity investors may sell their units in private transactions at any time, subject to compliance with applicable laws.

· to file with the SEC, within 90 days after the closing date of this offering, a registration statement (a “shelf registration statement”);

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· to use our commercially reasonable efforts to cause the shelf registration statement to become effective under the Securities Act within 180 days after the closing of this offering;

· pursuant to the shelf, or any other, registration statement;

· pursuant to Rule 144 under the Securities Act;

· to us or any of our subsidiaries; or

· in a private transaction in which the transferor’s rights under the registration rights agreement are not assigned to the transferee of the units.

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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 Vinson & Elkins L.L.P., counsel to us, insofar as it relates to matters of United States federal income tax law and legal conclusions with respect to those matters. This section is based upon 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 Vanguard Natural Resources, LLC and our limited liability company 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, foreign 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 Vinson & Elkins L.L.P. 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 Vinson & Elkins L.L.P. and are based on the accuracy of the representations made by us. Statements of fact do not represent opinions of Vinson & Elkins L.L.P.

For the reasons described below, Vinson & Elkins L.L.P. 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 (please read “—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 (please read “—Disposition of Units—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 (please read “—Tax Treatment of Operations—Depletion Deductions”);

(4) whether the deduction related to United States production activities will be available to a unitholder or the extent of such deduction to any unitholder (please read “—Tax Treatment of Operations—Deduction for United States Production Activities”); and

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(5) whether our method for depreciating Section 743 adjustments is sustainable in certain cases (please read “—Tax Consequences of Unit Ownership—Section 754 Election” and “—Uniformity of Units”).

Partnership Status

Except as discussed in the following paragraph, a limited liability company that has more than one member and that has not elected to be treated as a corporation is treated as a partnership for federal income tax purposes and, therefore, is not a taxable entity and incurs no federal income tax liability. Instead, each partner 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 are generally not taxable to the partner unless the amount of cash distributed to him is in excess of his adjusted 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 as the “Qualifying Income Exception,” exists with respect to publicly traded partnerships of which 90% or more of the gross income for every taxable year consists of “qualifying income.” Qualifying income includes income and gains derived from the exploration, development, mining or production, processing, 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 held for the production of income that otherwise constitutes qualifying income. We estimate that less than 5% of our current gross income is not qualifying income; however, this estimate could change from time to time. Based upon and subject to this estimate, the factual representations made by us, and a review of the applicable legal authorities, Vinson & Elkins L.L.P. 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 Vinson & Elkins L.L.P. on such matters. It is the opinion of Vinson & Elkins L.L.P. that, based upon the Internal Revenue Code, its regulations, published revenue rulings, court decisions and the representations described below, we will be classified as a partnership.

In rendering its opinion, Vinson & Elkins L.L.P. has relied on factual representations made by us. The representations made by us upon which Vinson & Elkins L.L.P. has relied include:

(a) Neither we, nor any of our limited liability company subsidiaries, have elected nor will we elect to be treated as a corporation;

(b) For each taxable year, more than 90% of our gross income will be income that Vinson & Elkins L.L.P. has opined or will opine is “qualifying income” within the meaning of Section 7704(d) of the Internal Revenue Code; and

(c) Each hedging transaction that we treat as resulting in qualifying income has been and will be appropriately identified as a hedging transaction pursuant to applicable Treasury Regulations, and has been and will be associated with oil, gas, or products thereof that are held or to be held by us in activities that Vinson & Elkins L.L.P. has opined or will opine result in qualifying income.

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, 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

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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 of capital to the extent of the unitholder’s tax basis in his units, or taxable capital gain, after the unitholder’s tax basis in his units is reduced to zero. 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 Vinson & Elkins L.L.P.’s opinion that we will be classified as a partnership for federal income tax purposes.

Unitholder Status

Unitholders who become members of Vanguard Natural Resources, LLC will be treated as partners of Vanguard Natural Resources, LLC for federal income tax purposes. Also, assignees who have executed and delivered transfer applications, and are awaiting admission as members, 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 Vanguard Natural Resources, LLC for federal income tax purposes.

Because there is no direct or indirect controlling authority addressing the federal tax treatment of assignees of units who are entitled to execute and deliver transfer applications and thereby become entitled to direct the exercise of attendant rights, but who fail to execute and deliver transfer applications, the opinion of Vinson & Elkins L.L.P. does not extend to these persons. Furthermore, a purchaser or other transferee of units who does not execute and deliver a transfer application may not receive some federal income tax information or reports furnished to record holders of units unless the units are held in a nominee or street name account and the nominee or broker has executed and delivered a transfer application for those units.

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. Please read “—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 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 Vanguard Natural Resources, LLC for federal income tax purposes.

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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, gains, losses and deductions 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. Please read “—Limitations on Deductibility of Losses.”

Any reduction in a unitholder’s share of our liabilities for which no partner bears the economic risk of loss, known as “non-recourse liabilities,” will be treated as a distribution of cash to that unitholder. A decrease in a 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 recapture, 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 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 will generally 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 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, 2010, will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be less than 30% of the cash distributed to the unitholder with respect to that period. Thereafter, we anticipate that 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.

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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 basis will be increased by his share of our income and by any increases in his share of our nonrecourse liabilities. That basis 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. Please read “—Disposition of Units—Recognition of Gain or Loss.”

Limitations on Deductibility of Losses

The deduction by a unitholder of his share of our losses will be limited to his tax basis in his units and, in the case of an individual unitholder or a corporate unitholder, if 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 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. 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 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 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 treated as a separate activity. Thus, a taxpayer’s interest in each oil or 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 must compute his at risk amount separately with respect to each oil or gas property we own, he may 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 are generally defined as trade or business activities in which the taxpayer does not materially

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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 only be available to offset our passive income generated in the future and will not be available to offset income from other passive activities or investments, including our investments or 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. Notwithstanding whether a natural gas and oil property is a separate activity, passive losses that are not deductible because they exceed a unitholder’s share of income we generate may be deducted 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 other applicable limitations on deductions, including the at-risk rules and the basis limitation.

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. The IRS has indicated that net passive income earned by a publicly traded partnership will be treated as investment income to its unitholders. 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 our limited liability company 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 our limited liability company 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.

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Allocation of Income, Gain, Loss and Deduction

In general, if we have a net profit, our items of income, gain, loss and deduction will be allocated among the unitholders in accordance with their percentage interests in us. If we have a net loss for an entire year, the loss will be allocated to our unitholders according to their percentage interests in us to the extent of their positive capital account balances.

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 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. 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.

Vinson & Elkins L.L.P. 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 limited liability company 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.

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 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. 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;

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· 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.

Vinson & Elkins L.L.P. 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. Please also read “—Disposition of Units—Recognition of 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% if the asset disposed of was held for more than twelve months at the time of disposition. The capital gains tax rate is scheduled to remain at 15% for years 2008 through 2010, and then increase to 20% beginning January 1, 2011.

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. Please also read, however, “—Allocation of 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 basis.

Where the remedial allocation method is adopted (which we will generally adopt as to all our properties), the Treasury Regulations under Section 743 of the Internal Revenue Code require a portion of the Section 743(b) adjustment that is attributable to recovery property under Section 168 of the Internal Revenue Code whose book basis is in excess of its tax basis to be depreciated over the remaining cost recovery period for the property’s unamortized book-tax disparity. Under Treasury Regulation Section 1.167(c)-1(a)(6), a Section 743(b) adjustment attributable to property subject to depreciation under Section 167 of the Internal Revenue Code, rather than cost recovery deductions under Section 168, is generally required to be depreciated using either the straight-line method or the 150% declining balance method. If we elect a method other than the remedial method, the depreciation and amortization methods and useful lives associated with the Section 743(b) adjustment, therefore, may differ from the methods and useful lives generally used to depreciate the inside basis in such properties. Under our limited liability company agreement, we are authorized to take a position to preserve the uniformity of units even if that

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position is not consistent with these and any other Treasury Regulations. Please read “—Uniformity of Units.”

Although Vinson & Elkins L.L.P. is unable to opine as to the validity of this approach because there is no direct or indirect controlling authority on this issue, we intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized book-tax disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the common basis of the property, or treat that portion as non-amortizable to the extent attributable to property the common basis of which is not amortizable. This method is consistent with the methods employed by other publicly traded partnerships but is arguably inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our assets. To the extent this Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized book-tax disparity, we will apply the rules described in the Treasury Regulations and legislative history. If we determine that this position cannot reasonably be taken, we may take a depreciation or amortization position under which all purchasers acquiring units in the same month would receive depreciation or amortization, whether attributable to common basis or a Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our assets. This kind of aggregate approach may result in lower annual depreciation or amortization deductions than would otherwise be allowable to some unitholders. Please read “—Uniformity of Units.” A unitholder’s tax basis for his units is reduced by his share of our deductions (whether or not such deductions were claimed on an individual’s income tax return) so that any position we take that understates deductions will overstate the unitholder’s basis in his units, which may cause the unitholder to understate gain or overstate loss on any sale of such units. Please read “—Disposition of Units—Recognition of Gain or Loss.” The IRS may challenge our position with respect to depreciating or amortizing the Section 743(b) adjustment we take to preserve the uniformity of the units. If such a challenge were sustained, the gain from the sale of units might be increased without the benefit of additional deductions.

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 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 basis reduction. Generally a built-in loss or a 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 or 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 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.

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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 income his share of our 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 income for his taxable year his share of more than twelve months of our income, gain, loss and deduction. Please read “—Disposition of Units—Allocations Between Transferors and Transferees.”

Depletion Deductions

Subject to the limitations on deductibility of 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.

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 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 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 (i) 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 (ii) 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.

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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 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 will result for alternative minimum tax purposes.

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 crude oil deposits 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 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 Gain or Loss.”

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Deduction for United States 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. 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 basis rules, the at-risk rules or the passive activity loss rules. Please read “—Tax Consequences of Unit Ownership—Limitations on Deductibility of 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 our qualified production activities income for that taxable year. It is not anticipated that we or our subsidiaries will pay material wages that will be allocated to our unitholders.

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.

Lease Acquisition Costs. The cost of acquiring natural gas and oil leaseholder 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. Please read “—Tax Treatment of Operations—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 which are reasonable in amount.

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Tax Basis, Depreciation and Amortization

The tax basis of our assets, such as casing, tubing, tanks, pumping units and other similar property, will be used for purposes of computing depreciation, depletion 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 (i) this offering will be borne by our existing unitholders, and (ii) any other offering will be borne by our unitholders as of that time. Please read “—Tax Consequences of Unit Ownership—Allocation of 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 are placed in service. Because we may 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. Please read “—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. Please read “—Tax Consequences of Unit Ownership—Allocation of Income, Gain, Loss and Deduction” and “—Disposition of Units—Recognition of Gain or Loss.”

The costs incurred 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 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 basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value or 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 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.

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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 held for more than one year will generally be taxable as long-term capital gain or loss. Capital gain recognized by an individual on the sale of units held more than twelve months 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, however, 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 appreciated “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 appreciated 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 only be used to offset capital gain 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 adjusted 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 basis units to sell as would be 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, 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.

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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 Code and most publicly traded partnerships use similar simplifying conventions, the use of this method may not be permitted under existing Treasury Regulations. Accordingly, Vinson & Elkins L.L.P. 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 only applies to 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, other than through a broker, generally is 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 is required to notify us in writing of that purchase within 30 days after the purchase, unless a broker or nominee will satisfy such requirement. We are required to notify the IRS of any such transfers of units and to furnish specified information to the transferor and transferee. Failure to notify us of a transfer of units may lead to the imposition of penalties.

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 twelve 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 us 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.

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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 the absence of uniformity, we may be unable to completely comply with a number of federal income tax requirements, both statutory and regulatory. A lack of uniformity can result from a literal application of Treasury Regulation Section 1.167(c)-1(a)(6). Any non-uniformity could have a negative impact on the value of the units. Please read “—Tax Consequences of Unit Ownership—Section 754 Election.”

We intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized book-tax disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the common basis of that property, or treat that portion as nonamortizable, to the extent attributable to property the common basis of which is not amortizable, consistent with the regulations under Section 743 of the Internal Revenue Code, even though that position may be inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our assets. Please read “—Tax Consequences of Unit Ownership—Section 754 Election.” To the extent that the Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized book-tax disparity, we will apply the rules described in the Treasury Regulations and legislative history. If we determine that this position cannot reasonably be taken, we may adopt a depreciation and amortization position under which all purchasers acquiring units in the same month would receive depreciation and amortization deductions, whether attributable to a common basis or Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our property. If this position is adopted, it may result in lower annual depreciation and amortization deductions than would otherwise be allowable to some unitholders and risk the loss of depreciation and amortization deductions not taken in the year that these deductions are otherwise allowable. This position will not be adopted if we determine that the loss of depreciation and amortization deductions will have a material adverse effect on the unitholders. If we choose not to utilize this aggregate method, we may use any other reasonable depreciation and amortization method to preserve the uniformity of the intrinsic tax characteristics of any units that would not have a material adverse effect on the unitholders. The IRS may challenge any method of depreciating the Section 743(b) adjustment described in this paragraph. If this challenge were sustained, the uniformity of units might be affected, and the gain from the sale of units might be increased without the benefit of additional deductions. Please read “—Disposition of Units—Recognition of Gain or Loss.”

Tax-Exempt Organizations and Other Investors

Ownership of units by employee benefit plans, other tax-exempt organizations, non-resident aliens, foreign corporations and other foreign persons raises issues unique to those investors and, as described below, may have substantially adverse tax consequences to them.

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.

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

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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 United States trade or business, that corporation may be subject to the United States 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 United States 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 United States 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 will 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 counsel 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.

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 limited liability company agreement

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allows our board of directors to appoint one of our officers who is a unitholder to serve as our Tax Matters Partner, subject to redetermination by our board of directors from time to time.

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:

(a) the name, address and taxpayer identification number of the beneficial owner and the nominee;

(b) a statement regarding whether the beneficial owner is:

(1) a person that is not a United States person,

(2) a foreign government, an international organization or any wholly owned agency or instrumentality of either of the foregoing, or

(3) a tax-exempt entity;

(d) 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 United States 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 by 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 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.

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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:

(1) for which there is, or was, “substantial authority,” or

(2) 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 apply to “tax shelters,” which we do not believe includes us.

A substantial valuation misstatement exists if the value of any property, or the adjusted 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 adjusted basis. No penalty is imposed unless the portion of the underpayment attributable to a substantial valuation misstatement exceeds $5,000 ($10,000 for most corporations). 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 tax avoidance 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 in excess of $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. Please read “—Information Returns and Audit Procedures” above.

Moreover, if we were to participate in a reportable transaction with a significant purpose to avoid or evade tax, or in any listed transaction, 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 will be subject to other taxes, including state and local income taxes, unincorporated business taxes, and estate, inheritance or intangible taxes that may be imposed by the various jurisdictions in which we conduct business or own property or in which you are a resident. We currently conduct business and own property in Kentucky and Tennessee. Both of these states currently impose a personal income tax on individuals and an entity level tax on certain corporations and other entities. We may also own property or do business in other states in the future. Although an analysis of

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those various taxes is not presented here, each prospective unitholder should consider their potential impact on his investment in us. You may not be required to file a return and pay taxes in some states because your income from that state falls below the filing and payment requirement. You will be required, however, to file state income tax returns and to pay state income taxes in many of the states in which we may do business or own property, and you may be subject to penalties for failure to comply with those requirements. In some states, tax losses may not produce a tax benefit in the year incurred and also may not be available to offset income in subsequent taxable years. Some of the states 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 state. Withholding, the amount of which may be greater or less than a particular unitholder’s income tax liability to the state, generally does not relieve a nonresident unitholder from the obligation to file an income tax return. Amounts withheld may be treated as if distributed to unitholders for purposes of determining the amounts distributed by us. Please read “—Tax Consequences of Unit Ownership—Entity-Level Collections.” Based on current law and our estimate of our future operations, we anticipate 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 states and localities, of his investment in us. Vinson & Elkins L.L.P. has not rendered an opinion on the state local, or foreign tax consequences of an investment in us. We strongly recommend that each prospective unitholder consult, and depend on, his own tax counsel or other advisor with regard to those matters. It is the responsibility of each unitholder to file all tax returns, that may be required of him.

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INVESTMENT IN OUR COMPANY 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)(l)(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.

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 prohibits employee benefit plans, and 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 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:

· 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;

· 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

· 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 our 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

Citigroup Global Markets Inc., or Citi, is acting as book-running manager of the offering and representative of the underwriters named below. Subject to the terms and conditions stated in the underwriting agreement dated the date of this prospectus, each underwriter named below has severally agreed to purchase, and we have agreed to sell to that underwriter, the number of common units set forth opposite the underwriter’s name.

Underwriters	Number of Common Units
Citigroup Global Markets Inc.
Lehman Brothers Inc.
A.G. Edwards & Sons, Inc.
Wachovia Capital Markets, LLC
Jefferies & Company, Inc.
BNP Paribas Securities Corp.
Total		5,000,000

The underwriting agreement provides that the obligations of the underwriters to purchase the common units included in this offering are subject to approval of legal matters by counsel and to other conditions. The underwriters are obligated to purchase all the common units (other than those covered by their option to purchase additional common units described below) if they purchase any common units.

The underwriters propose to offer some of the units directly to the public at the public offering price set forth on the cover page of this prospectus and some of the units to dealers at the public offering price less a concession not to exceed $ per unit. The underwriters may allow, and dealers may re-allow, a concession not to exceed $ per common unit on sales to other dealers. If all of the units are not sold at the initial offering price, Citi may change the public offering price and the other selling terms. Citi has advised us that the underwriters do not intend sales to discretionary accounts to exceed five percent of the total number of our common units offered by them.

We have granted to the underwriters an option, exercisable for 30 days from the date of this prospectus, to purchase up to 750,000 additional common units at the public offering price less the underwriting discount. The underwriters may exercise the option solely for the purpose of covering over-allotments, if any, in connection with this offering. To the extent the option is exercised, each underwriter must purchase a number of additional common units approximately proportionate to that underwriter’s initial purchase commitment.

We, all of our officers and directors, Nami and certain of its affiliates and the Private Investors have agreed that, for a period of 180 days from the date of this prospectus, we and they will not, without the prior written consent of Citi, dispose of or hedge any of our common units or any securities convertible into or exchangeable for our common units. Notwithstanding the foregoing, if (1) during the last 17 days of the 180-day period, we issue an earnings release, or material news or a material event relating to us occurs; or (2) 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, the restrictions described above shall continue to apply until the expiration of the 18-day period beginning on the issuance of the earnings release or the occurrence of the material news or material event.

Citi, in its sole discretion, may release any of the securities subject to these lock-up agreements at any time without notice. Citi has no present intent or arrangement to release any of the securities subject to these lock-up agreements. The release of any lock-up is considered on a case-by-case basis. Factors in deciding whether to release common units may include the length of time before the lock-up expires, the number of common units involved, the reason for the requested release, market conditions, the trading

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price of our common units, historical trading volumes of our common units and whether the person seeking the release is an officer, director or affiliate of us.

At our request, the underwriters have reserved up to 5% of the common units for sale at the initial offering price to persons who are our directors, officers and employees, or who are otherwise associated with us, through a directed unit program. The number of common units available for sale to the general public will be reduced by the number of directed common units purchased by participants in the program. Any directed common units not purchased will be offered by the underwriters to the general public on the same basis as all other common units offered. We have agreed to indemnify the underwriters against certain liabilities and expenses, including liabilities under the Securities Act, in connection with sales of the directed common units. Any common units purchased by our officers and directors or by our principal beneficial unitholders under the directed unit program will be subject to 180-day lock-up agreements, which will be subject to extension as described above, following this offering.

Prior to this offering, there has been no public market for our common units. Consequently, the initial public offering price for the common units will be determined by negotiations between us and Citi. The principal factors considered in determining the initial public offering price include the following:

· our results of operations;

· our current financial condition;

· our future prospects;

· our markets;

· the economic conditions in and future prospects for the industry in which we compete;

· our management; and

· currently prevailing general conditions in the equity securities markets, including current market valuations of publicly traded partnerships and limited liability companies considered comparable to our company.

We cannot assure you, however, that the prices at which the common units will sell in the public market after this offering will not be lower than the initial public offering price or that an active trading market in our common units will develop and continue after this offering.

Our common units have been approved for listing, subject to official notice of issuance, on the NYSE Arca under the symbol “VNR.”

The following table shows the underwriting discounts and commissions that we are to pay to the underwriters in connection with this offering. These amounts are shown assuming both no exercise and full exercise of the underwriters’ option to purchase additional common units.

No Exercise

Full Exercise

Paid by us per common unit

We will pay Citi a structuring fee equal to approximately $0.4 million (or approximately $0.5 million if the underwriters exercise their option to purchase additional common units in full) for its evaluation, analysis and structuring of our company.

We estimate that the total expenses of this offering, excluding underwriting discounts and commissions and the structuring fee, will be $2.5 million, all of which will be paid by us.

In connection with the offering, Citi on behalf of the underwriters may purchase and sell common units in the open market. These transactions may include short sales, syndicate covering transactions and stabilizing transactions. Short sales involve syndicate sales of common units in excess of the number of

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common units to be purchased by the underwriters in the offering, which creates a syndicate short position. “Covered” short sales are sales of common units made in an amount up to the number of common units represented by the underwriters’ option to purchase additional common units. In determining the source of common units to close out the covered syndicate short position, the underwriters will consider, among other things, the price of common units available for purchase in the open market compared to the price at which they may purchase common units through their option to purchase additional common units. Transactions to close out the covered syndicate short position involve either purchases of the common units in the open market after the distribution has been completed or the exercise of their option to purchase additional common units. The underwriters may also make “naked” short sales of common units in excess of their option to purchase additional common units. The underwriters must close out any naked short position by purchasing common units in the open market. A naked short position is more likely to be created if the underwriters are concerned that there may be downward pressure on the price of the common units in the open market after pricing that could adversely affect investors who purchase in the offering. Stabilizing transactions consist of bids for or purchases of common units in the open market while the offering is in progress.

The underwriters also may impose a penalty bid. Penalty bids permit the underwriters to reclaim a selling concession from a syndicate member when an underwriter repurchases common units originally sold by that syndicate member in order to cover syndicate short positions or make stabilizing purchases.

Any of these activities, as well as purchases by the underwriters for their own accounts, may have the effect of preventing or retarding a decline in the market price of the common units. They may also cause the price of the common units to be higher than the price that would otherwise exist in the open market in the absence of these transactions. The underwriters may conduct these transactions on the NYSE Arca or otherwise. If the underwriters commence any of these transactions, they may discontinue them at any time.

Citi has performed from time to time investment banking and advisory services for us and Nami for which it has received and will receive customary fees and expenses. An affiliate of Citi is the administrative agent, co-lead arranger, sole bookrunner and co-syndication agent with respect to our reserve-based credit facility. A portion of the proceeds of this offering will be used to repay amounts owed to this affiliate of Citi under our reserve-based credit facility. Please read “Use of Proceeds.” Another affiliate of Citi is the counterparty on our hedging transactions. The underwriters may, from time to time, engage in other transactions with and perform other services for us in the ordinary course of our business.

A prospectus in electronic format may be made available by one or more of the underwriters. Citi may agree to allocate a number of common units to underwriters for sale to their online brokerage account holders. Citi will allocate common units to underwriters that may make Internet distributions on the same basis as other allocations. In addition, common units may be sold by the underwriters to securities dealers who resell common units to online brokerage account holders.

Other than the prospectus in electronic format, the information on any underwriter’s web site and any information contained in any other web site maintained by an underwriter 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 in its capacity as an underwriter and should not be relied upon by investors.

We (or our successors) have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act, and to contribute to payments that the underwriters may be required to make for any such liabilities.

Because the National Association of Securities Dealers, Inc. views the common units offered by this prospectus as interests in a direct participation program, the offering is being made in compliance with Rule 2810 of the NASD’s Conduct 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 UNITS

The validity of the units will be passed upon for us by Vinson & Elkins L.L.P., Houston, Texas. Certain legal matters in connection with the units offered by us will be passed upon for the underwriters by Andrews Kurth LLP, Houston, Texas.

EXPERTS

The consolidated financial statements of Vanguard Natural Gas, LLC (formerly Nami Holding Company, LLC) and subsidiaries as of and for the year ended December 31, 2006 have been audited by UHY LLP, Independent Registered Public Accounting Firm, as set forth in their report thereon appearing elsewhere herein, and are included in reliance upon such report given on the authority of such firm as experts in accounting and auditing.

The consolidated financial statements of Vanguard Natural Gas, LLC and subsidiaries as of and for the years ended December 31, 2005 and 2004 have been audited by Rodefer Moss & Co, pllc, Independent Registered Public Accounting Firm, as set forth in their report thereon appearing elsewhere herein, and are included in reliance upon such report given on the authority of such firm as experts in accounting and auditing.

The balance sheet of Vanguard Natural Resources, LLC as of March 31, 2007 has been audited by UHY LLP, Independent Registered Public Accounting Firm, as set forth in their report thereon appearing elsewhere herein, and are included in reliance upon such report given on the authority of such firm as experts in accounting and auditing.

Information included in this prospectus regarding our estimated quantities of natural gas and oil reserves at March 31, 2007 and December 31, 2006 was prepared by Netherland Sewell & Associates Inc., independent petroleum engineers, as stated in their reserve report with respect thereto. A summary of the reserve report of Netherland Sewell & Associates, Inc. for our reserves as of March 31, 2007 is attached hereto as Appendix C, in reliance upon the authority of said firm as experts with respect to the matters covered by their report and the giving of their report.

Information included in this prospectus regarding our estimated quantities of natural gas and oil reserves at December 31, 2005 was prepared by Schlumberger Data and Consulting Services, independent petroleum engineers, as stated in their reserve report with respect thereto.

Information included in this prospectus regarding our estimated quantities of natural gas and oil reserves at December 31, 2004 was prepared by Wright & Company, independent petroleum engineers, as stated in their reserve report with respect thereto.

WHERE YOU CAN FIND MORE INFORMATION

We have filed with the Securities and Exchange Commission, or the SEC, a registration statement on Form S-l regarding the units. This prospectus does not contain all of the information found in the registration statement. For further information regarding us and the 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., 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., 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 at http://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 to Financial Statements

		Page

Vanguard Natural Resources, LLC and Subsidiaries Unaudited Consolidated Financial Statements
Unaudited Consolidated Balance Sheet		F-2
Unaudited Consolidated Statement of Operations		F-3
Unaudited Consolidated Statement of Cash Flows		F-4
Unaudited Consolidated Statement of Comprehensive Income (Loss)		F-5
Notes to the Consolidated Financial Statements		F-6
Vanguard Natural Gas, LLC and Subsidiaries Consolidated Financial Statements
Reports of Independent Registered Public Accounting Firms		F-15
Consolidated Balance Sheet		F-17
Consolidated Statement of Operations		F-18
Consolidated Statement of Members’ Equity		F-19
Consolidated Statement of Cash Flows		F-20
Notes to the Consolidated Financial Statements		F-21
Vanguard Natural Resources, LLC Unaudited Pro Forma Consolidated Financial Statements
Unaudited Pro Forma Consolidated Balance Sheet		F-37
Unaudited Pro Forma Consolidated Statement of Operations for the Year Ended December 31, 2006		F-38
Unaudited Pro Forma Consolidated Statement of Operations for the Six Months Ended June 30, 2007		F-39
Notes to Unaudited Pro Forma Consolidated Financial Statements		F-40
Vanguard Natural Resources, LLC Balance Sheet
Report of Independent Registered Public Accounting Firm		F-45
Balance Sheet		F-46
Notes to Balance Sheet		F-47

F-1

Vanguard Natural Resources, LLC and Subsidiaries
Consolidated Balance Sheet

				Vanguard
	Vanguard			Predecessor
	June 30,			December 31,
	2007			2006
	(Unaudited)
Assets
Current assets
Cash and cash equivalents	$	4,445,007		$	1,730,956
Trade accounts receivable, net	4,190,075			5,269,067
Receivables due from affiliates	—			14,650,936
Other receivables	—			234,456
Derivative assets	3,355,539			—
Deferred offering costs	1,571,993			—
Other current assets	12,372			283,884
Total current assets	13,574,986			22,169,299
Property and equipment
Land	—			46,350
Buildings	—			10,850
Furniture and fixtures	31,211			846,580
Machinery and equipment	—			12,681,363
Less: accumulated depreciation	(166		)	(1,712,535		)
Total property and equipment	31,045			11,872,608
Natural gas and oil properties, net—full cost method	101,610,952			104,683,610
Other assets
Derivative assets	3,277,563
Deferred financing costs	1,052,036
Other assets	455,883			—
Total Assets	$	120,002,465		$	138,725,517
Liabilities and members’ equity (deficit)
Current liabilities
Accounts payable—trade	$	1,729,104		$	8,756,937
Accounts payable—natural gas and oil	734,238			1,441,941
Payables to affiliates	2,267,650			—
Derivative liabilities	—			2,022,079
Deferred swap liability	7,322,685			—
Accrued expenses	527,095			1,230,686
Due to member	—			75,000
Total current liabilities	12,580,772			13,526,643
Long-term debt	109,000,000			94,067,500
Derivative liabilities	4,048,588			—
Asset retirement obligations	435,638			418,533
Total liabilities	126,064,998			108,012,676
Members’ equity (deficit)
Members’ capital	4,395,731			30,712,841
Other comprehensive loss	(10,458,264		)	—
Total members’ equity (deficit)	(6,062,533		)	30,712,841
Total liabilities and members’ equity (deficit)	$	120,002,465		$	138,725,517

See accompanying notes to consolidated financial statements.

F-2

Vanguard Natural Resources, LLC and Subsidiaries
Consolidated Statement of Operations
(Unaudited)

					Vanguard
	Vanguard				Predecessor
	Six Months Ended				Six Months Ended
	June 30,				June 30,
	2007				2006
Revenues
Natural gas and oil sales		$	19,068,353			$	19,415,983
Realized losses from derivative contracts		(1,665,852		)		(2,341,474		)
Change in fair value of derivative contracts		—				11,424,307
Total revenues		17,402,501				28,498,816
Costs and expenses
Lease operating expenses		2,460,420				2,374,800
Depreciation, depletion and amortization		4,320,289				4,047,066
Selling, general and administrative		1,215,489				959,898
Bad debt expense		1,007,458
Taxes other than income		890,992				651,039
Total costs and expenses		9,894,648				8,032,803
Income from operations		7,507,853				20,466,013
Other income (expense)
Interest income		27,646				18,253
Interest expense		(4,419,814		)		(3,783,834		)
Loss on extinguishment of debt		(2,501,528		)		—
Total other expense		(6,893,696		)		(3,765,581		)
Net income		$	614,157			$	16,700,432
Pro forma net income per unit:
Pro forma net income per unit		$	0.06
Pro forma units outstanding		11,000,000

See accompanying notes to consolidated financial statements.

F-3

Vanguard Natural Resources, LLC and Subsidiaries
Consolidated Statement of Cash Flows
(Unaudited)

					Vanguard
	Vanguard				Predecessor
	Six Months Ended				Six Months Ended
	June 30,				June 30,
	2007				2006
Operating activities
Net income		$	614,157			$	16,700,432
Adjustments to reconcile net income to net cash (used in) provided by operating activities:
Depreciation, depletion and amortization		4,320,289				4,047,066
Amortization of deferred financing costs		142,234				—
Bad debt expense		1,007,458				—
Change in fair value of derivative contracts		—				(11,424,307		)
Non-cash unit compensation		563,143				—
Changes in operating assets and liabilities:
Trade accounts receivable		(322,027		)		1,556,371
Receivables due from affiliates		(2,083,796		)		(1,295,685		)
Other receivables		—				44,678
Price risk management activities, net		(7,742,172		)		—
Other current assets		(12,372		)		(2,781,334		)
Accounts payable		2,393,459				(261,359		)
Accrued expenses		(1,713,858		)		643,403
Net cash (used in) provided by operating activities		(2,833,485		)		7,229,265
Investing activities
Additions to property and equipment		(31,211		)		(4,043,484		)
Additions to natural gas and oil properties		(6,132,607		)		(10,282,047		)
Deposits		(455,883		)		—
Net cash used in investing activities		(6,619,701		)		(14,325,531		)
Financing activities
Proceeds from borrowings		114,600,000				6,000,000
Repayments of debt		(99,667,500		)		—
Contributions from members		41,221,000				—
Distributions to member		(41,220,000		)		(803,945		)
Financing costs		(1,194,270		)		—
Offering costs		(1,571,993		)		—
Net cash provided by financing activities		12,167,237				5,196,055
Net increase (decrease) in cash and cash equivalents		2,714,051				(1,900,211		)
Cash and cash equivalents, beginning of period		1,730,956				3,041,468
Cash and cash equivalents, end of period		$	4,445,007			$	1,141,257
Supplemental cash flow information:
Cash paid for interest		$	4,826,132			$	4,722,696
Non-cash financing and investing activities:
Accumulated other comprehensive loss		$	11,191,768			$	—
Deferred swap liability		$	7,322,685			$	—
Asset retirement obligations		$	6,273			$	91,448

See accompanying notes to consolidated financial statements.

F-4

Vanguard Natural Resources, LLC and Subsidiaries
Consolidated Statement of Comprehensive Income (Loss)
(Unaudited)

					Vanguard
	Vanguard				Predecessor
	Six Months Ended				Six Months Ended
	June 30,				June 30,
	2007				2006
Net income		$	614,157			$	16,700,432
Net gains (losses) from cash flow hedging activities:
Unrealized mark-to-market losses arising during period		(11,191,768		)		—
Reclassification adjustments for changes in initial value to settlement date		733,504				—
Other comprehensive loss		(10,458,264		)		—
Comprehensive income (loss)		$	(9,844,107	)		$	16,700,432

See accompanying notes to consolidated financial statements.

F-5

Vanguard Natural Resources, LLC and Subsidiaries
Notes to Consolidated Financial Statements
For the Six Months Ended June 30, 2007
(Unaudited)

1. Basis of Presentation and Significant Accounting Policies

Basis of Presentation

In April 2007, the sole member of Vanguard Natural Gas, LLC (formerly Nami Holding Company, LLC) (“VNG”) contributed all of the issued and outstanding common units in VNG to Vanguard Natural Resources, LLC (“VNR”) for 6 million common units representing all of the issued and outstanding common units of VNR.

Effective January 5, 2007, VNG conveyed to Vinland Energy Eastern, LLC and its affiliates (collectively referred to as “Vinland”) 60% of its working interest in approximately 107,000 gross undeveloped acres surrounding or adjacent to our existing wells in an area of mutual interest, interests in an additional 125,000 undeveloped acres and certain coal bed methane rights located in the Appalachian Basin, the rights to any natural gas and oil on our acreage located in depths above and 100 feet below our known producing horizons, all of our property, plant and equipment assets and all of our employees, except two officers, pursuant to a restructuring plan. We retained all of our proved producing wells and associated reserves along with the remaining 40% working interest in the approximate 107,000 gross undeveloped acres surrounding or adjacent to our existing wells in an area of mutual interest. In addition, in February 2007, VNG changed the name of the operating company from Nami Holding Company, LLC to Vanguard Natural Gas, LLC (“VNG”). Collectively, we refer to these events as “the Restructuring.”

The consolidated financial statements as of and for the six months ending June 30, 2007 include the accounts of VNR, its wholly-owned subsidiary VNG and VNG’s wholly-owned operating subsidiaries which include: Trust Energy Company, LLC, (“TEC”), VNR Holdings, Inc (“VNRH”) and Ariana Energy, LLC, (“Ariana Energy”). In conjunction with the Restructuring, Nami Resources Company, LLC conveyed its assets to Vinland or TEC as appropriate and is no longer a wholly-owned subsidiary of VNG and therefore is no longer consolidated in these consolidated financial statements. The consolidated financial statements as of December 31, 2006 and for the six months ending June 30, 2006 are based on the annual audited and interim period unaudited historical financial statements of VNG prior to the Restructuring. As such, these periods are labeled Vanguard Predecessor and are separated from VNR financial data by a bold black line. All significant intercompany accounts and transactions have been eliminated in the consolidated financial statements. Certain prior year amounts have been reclassified to conform to the current year presentation.

VNG was formed in Kentucky on December 15, 2004 and its principal business is to hold interests in TEC, VNRH and Ariana Energy.

TEC was formed in Kentucky on December 15, 2004. Its principal business consists of natural gas and oil development and exploitation of mature, long-lived natural gas and oil properties which includes the operation and maintenance of its own pipeline gathering system in the Appalachian region of eastern Kentucky and Tennessee.

VNRH was formed in Delaware on March 28, 2007. Its principal business it to provide general employment related services, including payroll and employment administration, as well as information technology and communication services to VNR.

F-6

Vanguard Natural Resources, LLC and Subsidiaries
Notes to Consolidated Financial Statements (Continued)
For the Six Months Ended June 30, 2007
(Unaudited)

1. Basis of Presentation and Significant Accounting Policies (Continued)

Ariana Energy was formed in Tennessee on April 26, 2002 and its principal business consists of natural gas and oil development and exploitation of mature, long-lived natural gas and oil properties in Tennessee.

VNR, VNG, TEC, VNRH and Ariana Energy are hereafter collectively referred to as “us”, “we”, “our” or “the Company”.

Significant Accounting Policies

Our significant accounting policies and accounting pronouncements issued but not yet adopted are discussed in our audited 2006 Consolidated Financial Statements located on page F-21.

2. Accounts Receivable and Allowance for Doubtful Accounts

We established an approximate $1 million provision for a loss on the entire amount due from a customer which filed for protection under Chapter 11 of the Bankruptcy Code in May 2007. The account receivable was due from oil sales through December 2006 at which time we ceased selling oil to the customer. As the amount of any potential recovery is uncertain, we elected to reserve the entire balance and it is reflected as bad debt expense on our consolidated statement of operations for the six months ended June 30, 2007. We began selling our oil production to a new customer beginning in March 2007.

3. Credit Facilities and Long-Term debt

Our credit facilities and long-term debt consisted of the following (in millions):

					Amount Outstanding
Description	Interest Rate			Maturity Date	June 30, 2007			December 31, 2006
$75 million Senior Secured Revolver		Variable		January 31, 2007		$	—		$	63.1
$40 million TCW Senior Secured Notes		13	%	December 29, 2011		—			31.0
$200 million Senior Secured Revolver		Variable		January 3, 2011		109.0			—
Total						$	109.0		$	94.1

$75 million Senior Secured Revolver

On June 30, 2003, we entered into a $75 million senior secured revolving credit facility with the Bank of Texas (“Senior Revolver”) which amended and restated in its entirety a loan agreement dated March 23, 2001. The Senior Revolver had an original maturity date of June 30, 2006 but was extended through amendments to January 31, 2007. The available credit line (“Borrowing Base”) was subject to adjustment from time to time but not less than on a semi-annual basis based on the projected discounted present value (as determined by independent petroleum engineers) of estimated future net cash flows from certain proved natural gas and oil reserves of the Company. At December 31, 2006, the Borrowing Base was $65 million. The Senior Revolver was secured by a mortgage lien on certain natural gas and oil properties, field equipment and accounts receivable, among other assets held by the Company. Interest rates under this credit facility were at the election of the Company based on Euro-Dollars (LIBOR) or

F-7

Vanguard Natural Resources, LLC and Subsidiaries
Notes to Consolidated Financial Statements (Continued)
For the Six Months Ended June 30, 2007
(Unaudited)

3. Credit Facilities and Long-Term debt (Continued)

Stated Rate (Prime) indications, plus a margin. The margin could range from Prime minus 0.25% to Prime plus 0.25% or LIBOR plus 1.875% to LIBOR plus 2.625% depending on borrowing base utilization. At December 31, 2006, our interest rate was 8.5%. The availability of borrowings was subject to various conditions, which included compliance with the financial covenants and ratios required by the facility, absence of default under the facility and the continued accuracy of the representations and warranties contained in the facility. At December 31, 2006, the financial coverage ratios under the facility required that our debt to EBITDA (as defined in the loan agreement) ratio not exceed 4.0 to 1.0 and our current ratio (as defined in the loan agreement) not be less than 1.0 to 1.0. In addition, affiliate investments (as defined in the loan agreement) could not exceed $10 million.

Since the inception of the Senior Revolver, seven amendments were entered into which amended certain terms of the loan agreement including increasing the number of participating lenders, changing the maximum borrowing base, extending the maturity date, reducing the interest costs, adding a new financial covenant and adding new reporting requirements. In addition, on December 30, 2004, our second amendment reduced the amount of natural gas and oil properties pledged under the Senior Revolver. Certain pledged natural gas and oil properties were released so that they could be pledged under a new $40 million note facility as described below. As consideration for releasing the pledged properties, indebtedness under the Senior Revolver was reduced by $16 million using proceeds from the new note facility.

On January 3, 2007, all amounts due under the Senior Revolver were repaid and a new long-term credit facility was established as discussed below, and therefore, amounts due under the Senior Revolver are reported on the balance sheet as a long-term obligation despite the maturity date falling within one year of December 31, 2006.

$40 million TCW Senior Secured Notes

On December 30, 2004, we entered into a $40 million Senior Secured Notes facility due to TCW Asset Management Company (the “TCW Notes”). The TCW Notes original maturity was on December 29, 2011 and required quarterly interest payments at 13% per annum. The TCW Notes were secured by a mortgage lien on certain natural gas and oil properties. Prior to December 30, 2006, the availability of borrowings was subject to various conditions, which included compliance with the financial covenants and ratios required by the facility, absence of default under the facility and the continued accuracy of the representations and warranties contained in the facility. After December 30, 2006, no new borrowings were available. At December 31, 2006, the financial coverage ratios under the facility required that our collateral coverage ratio (as defined in the loan agreement) not be less than 1.2 to 1.0 and our current ratio (as defined in the loan agreement) not be less than 1.0 to 1.0. We could not borrow, repay, and reborrow under the facility. Optional prepayments were not permitted prior to December 31, 2006 and were subject to a range of penalties thereafter until December 31, 2008 at which point no prepayment penalties applied.

On January 3, 2007, all amounts due under the TCW Notes were repaid and a new credit facility was established as discussed below. We recorded a $2.5 million loss on the extinguishment of this debt as the loan agreement required an early prepayment penalty.

F-8

Vanguard Natural Resources, LLC and Subsidiaries
Notes to Consolidated Financial Statements (Continued)
For the Six Months Ended June 30, 2007
(Unaudited)

3. Credit Facilities and Long-Term debt (Continued)

New $200 Million Senior Secured Revolver

In January 2007, the Company entered into a new four year $200 million revolving credit facility (“Credit Facility”) with two banks. All outstanding debt under the TCW Notes (including an early payment penalty of $2.5 million) and the Senior Revolver were repaid with borrowings under the new Credit Facility. The available credit line (“Borrowing Base”) is subject to adjustment from time to time but not less than on a semi-annual basis based on the projected discounted present value (as determined by independent petroleum engineers) of estimated future net cash flows from certain proved natural gas and oil reserves of the Company. The initial Borrowing Base was set at $115.5 million and is secured by a first lien security interest in all of the Company’s natural gas and oil properties. However, the borrowing base is subject to a $1 million reduction per month starting on July 1, 2007 through September 30, 2007 at which time a new borrowing base redetermination date is scheduled. See Note 8. Subsequent Events for further discussion.

Interest rates under the Credit Facility are based on Euro-Dollars (LIBOR) or ABR (Prime) indications, plus a margin. The applicable margin and other fees increase as the utilization of the borrowing base increases as follows:

	Borrowing Base Utilization Grid
Borrowing Base Utilization Percentage	£25	%	>25% £50	%	>50% £75	%	>75	%
Eurodollar Loans	1.375	%	1.500	%	1.750	%	2.00	%
ABR Loans	0.250	%	0.500	%	0.750	%	1.00	%
Commitment Fee Rate	0.250	%	0.375	%	0.375	%	0.50	%
Letter of Credit Fee	1.375	%	1.500	%	1.750	%	2.00	%

The Credit Agreement contains a number of customary covenants that require the Company to maintain certain financial ratios, limit the Company’s ability to incur additional debt, sell assets, create liens, or make certain distributions. At June 30, 2007, we were in compliance with our debt covenants. In addition, after consideration of the third amendment to the Credit Facility described below, the first $100 million of proceeds received from an equity infusion must be applied to the repayment of borrowings under the Credit Facility (“Equity Event”). Since borrowings under the Credit Facility were not reduced by $100 million by July 1, 2007, the applicable margin increased as follows:

Eurodollar Loans	3.00	%
ABR Loans	4.00	%
Commitment Fee Rate	0.50	%
Letter of Credit Fee	3.00	%

F-9

Vanguard Natural Resources, LLC and Subsidiaries
Notes to Consolidated Financial Statements (Continued)
For the Six Months Ended June 30, 2007
(Unaudited)

3. Credit Facilities and Long-Term debt (Continued)

2008 and 2009 be put in place to create a price floor for anticipated production from new wells drilled. See Note 4. Price Risk Management Activities for further discussion.

In March 2007, the first amendment to the Credit Facility was executed. The amendment redefined the method to calculate a financial covenant to include the impact of acquisitions and divestitures. In addition, it clarified that the increase in the applicable margin which commenced on July 1, 2007 will continue only until the Equity Event occurs.

In April 2007, the second amendment to the Credit Facility was executed. The amendment redefined change of control to allow for the sale of common units to private investors more fully described below in Note 6. Common Units and Pro Forma Net Income per Unit, recognized certain contract rights to receive approximately 99% of the net proceeds (after deducting royalties paid to other parties, severance taxes, third-party transportation costs, costs incurred in the operation of the wells and overhead costs) from the sale of production from certain producing gas and oil wells located within the Asher lease.

In May 2007, the third amendment to the Credit Facility was executed. The amendment increased the amount of proceeds from an equity infusion that must be applied to the repayment of borrowings under the Credit Facility from $80 million to $100 million. A new Minimum Liquidity covenant was added which requires us to maintain unencumbered liquid assets of at least $2 million which includes unused availability under the borrowing base. Also, the amount of other debt we can incur was temporarily increased from $1 million to $7.5 million which allowed us to incur the debt necessary to reset our 2007, 2008 and 2009 natural gas swaps at higher prices more fully described in Note 4. Price Risk Management Activities. The other debt is required to be repaid at the earlier of five business days after closing of a public offering of equity securities or September 3, 2007.

4. Price Risk Management Activities

From time to time, the Company enters into natural gas swap agreements with counterparties to hedge price risk associated with a portion of its production. These derivatives are not held for trading purposes. Under these price swaps, the Company receives a fixed price on a notional quantity of natural gas in exchange for paying a variable price based on a market index, such as Columbia Gas Appalachian, or TECO, natural gas futures. During 2006, natural gas swaps covered 2,673,000 MMBtu, fixing the sales price of this natural gas at an average of $6.29 per MMBtu.

At December 31, 2006, the Company had open natural gas price swap contracts covering its 2007 production as follows:

	Natural Gas Price Swaps
Contract period	Volume in MMBtu		Weighted Average Price
First quarter 2007		413,000		$	6.04
Second quarter 2007		637,000		$	6.04
Third quarter 2007		644,000		$	6.04
Fourth quarter 2007		644,000		$	6.04
Total 2007		2,338,000		$	6.04

F-10

Vanguard Natural Resources, LLC and Subsidiaries
Notes to Consolidated Financial Statements (Continued)
For the Six Months Ended June 30, 2007
(Unaudited)

4. Price Risk Management Activities (Continued)

The derivative contracts entered into in 2006 were not specifically designated as hedges under SFAS No. 133 Accounting for Derivative Instruments and Hedging Activities and therefore did not qualify for hedge accounting treatment. These derivative contracts are recorded at fair value on the consolidated balance sheet as short-term and long-term liabilities based upon their anticipated settlement date. The change in fair value of these derivative contracts is recorded in the consolidated statement of operations.

On January 3, 2007, the natural gas price swaps referred to above were terminated which resulted in the Company incurring swap termination fees of $2.8 million. New natural gas derivative contracts were put in place in conjunction with entering into a new credit facility as described in Note 3. Credit Facilities and Long-Term Debt. A summary of the derivative contracts entered into in January 2007 is as follows:

Swap Agreements

Contract Period	Volume in MMBtu		Weighted Average Fixed Price
July – December 2007		1,708,357		$	7.50
2008		3,016,134		$	8.14
2009		2,657,046		$	7.87
2010		2,387,640		$	7.53
2011		2,196,012		$	7.15

Put Option Contracts

Contract Period	Volume in MMBtu		Purchased Price Floor
February – December 2007		1,356,480		$	7.50
2008		2,211,366		$	7.50
2009		1,840,139		$	7.50

Collar Contracts

Contract Period	Volume in MMBtu		Price Floor			Price Ceiling
February – June 2007		1,500,000		$	6.45		$	7.45

The Company paid $6.5 million for the put option contracts referenced above. Payments for the put option contracts and the swap termination fee were funded with borrowings under the Credit Facility.

In May 2007, we reset our 2007, 2008 and 2009 natural gas swaps at higher prices as follows:

Contract Period	Volume in MBtu		Original Weighted Average Fixed Price			New Weighted Average Fixed Price
July – December 2007		1,708,357		$	7.50		$	9.00
2008		3,016,134		$	8.14		$	9.00
2009		2,657,046		$	7.87		$	8.85

F-11

Vanguard Natural Resources, LLC and Subsidiaries
Notes to Consolidated Financial Statements (Continued)
For the Six Months Ended June 30, 2007
(Unaudited)

4. Price Risk Management Activities (Continued)

We incurred a $7.3 million deferred swap payment obligation with the derivative counterparty which accrues interest daily at 7.36% and is payable at the earlier of five days after the closing of an equity issuance or September 3, 2007.

The derivative contracts entered into in January 2007, and reset in May 2007, were specifically designated as hedges under SFAS No. 133 Accounting for Derivative Instruments and Hedging Activities and therefore qualify for hedge accounting treatment. These derivative contracts are recorded at fair value on the consolidated balance sheet as short-term and long-term liabilities based upon their anticipated settlement date. The change in fair value of these derivative contracts is recorded in Other Comprehensive Income.

5. Related Party Transactions

At June 30, 2007 and December 31, 2006, amounts payable to our primary member were none and $75,000, respectively. Historically, we maintained relationships with several closely related companies that directly supported us through administrative and operational services. The total cost for services performed by these affiliates was none and $1.3 million for the six months ended June 30, 2007 and the year ended December 31, 2006, respectively. The Company has also historically funded certain capital requirements of its affiliates. As of December 31, 2006, receivables due from these affiliates were $14.7 million. These companies are affiliated through common ownership with our primary member. All of the related party balances at December 31, 2006, were conveyed to other entities pursuant to the Restructuring and therefore no receivable balances were outstanding from these affiliates at June 30, 2007. In addition, as of the Restructuring no additional funding of these related parties will occur.

Pursuant to the Restructuring, we rely on Vinland to execute our drilling program, operate our wells and gather our natural gas in Appalachia. We will reimburse Vinland $60 per well per month (in addition to normal third party operating costs) for operating our current natural gas and oil properties in Appalachia under a Management Services Agreement (“MSA”) which costs are reflected in our lease operating expenses. Also, Vinland will receive a $0.25 per mcf transportation fee on existing wells drilled at December 31, 2006 and $0.55 per mcf transportation fee on any new wells drilled subsequently in the AMI. This transportation fee only encompasses transporting the natural gas to third party pipelines at which point additional transportation fees to natural gas markets would apply. These transportation fees are outlined under a Gathering and Compression Agreement (“GCA”) with Vinland and are reflected in our lease operating expenses. For the quarter and six months ended June 30, 2007, costs incurred under the MSA were $0.1 million and $0.3 million, respectively. For the quarter and six months ended June 30, 2007, costs incurred under the GCA were $0.3 million and $0.7 million, respectively. A payable of $2.3 million is reflected on our June 30, 2007 consolidated balance sheet in connection with these agreements and direct expenses incurred by Vinland related to the drilling of new wells and operations of all of our existing wells in Appalachia.

F-12

Vanguard Natural Resources, LLC and Subsidiaries
Notes to Consolidated Financial Statements (Continued)
For the Six Months Ended June 30, 2007
(Unaudited)

6. Common Units and Pro Forma Net Income per Unit

In April 2007, the sole member of VNG (formerly Nami Holding) contributed all of the issued and outstanding common units in VNG to VVNR for 6 million common units representing all of the issued and outstanding common units of VNR. The sole member then completed a private equity offering pursuant to which he sold 2.29 million common units to certain private investors for $41.2 million. The proceeds of this private equity offering were used to make a distribution to the sole member. The sole member used a portion of these funds to capitalize Vinland and Vinland paid us $3.9 million to reduce outstanding accounts receivable from Vinland.

In April 2007, we filed a registration statement on Form S-1 with the Securities and Exchange Commission in anticipation of offering 5 million common units to the public and have subsequently filed one amendment in July 2007.

The consolidated statement of operations reflects a pro forma net income per unit amount calculated using 11 million units. This assumes that all units, including the 5 million we anticipate offering to the public, were outstanding from the beginning of 2007. No calculation was made for the Vanguard Predecessor period.

7. Unit-Based Compensation

In April 2007, the sole member reserved 460,000 restricted Class B units in VNR for issuance to employees of VNRH. Certain members of management were granted 365,000 restricted Class B units in VNR in April 2007 which vest two years from the date of a successful initial public offering of our equity securities. In addition, another 55,000 restricted VNR Class B units were reserved for issuance for two other employees that were hired in April and May, 2007 which will vest over three years and were issued in August 2007 (see Note 8. Subsequent Events for further discussion). There are an additional 40,000 Class B units available to be issued in the future. These Class B units were granted as partial consideration for services to be performed under employment contracts and thus will be subject to accounting for these grants under SFAS No. 123(R), Share-Based Payment.

The fair value of restricted units issued is determined based on the fair market value of VNR units on the date of the grant. This value is amortized over the vesting period as referenced above. A summary of the status of the non-vested units as of June 30, 2007 is presented below:

	Number of Non-vested Units		Weighted Average Grant Date Fair Value
Non-vested units at December 31, 2006		—		$	—
Granted		365,000		18.00
Non-vested units at June 30, 2007		365,000		$	18.00

At June 30, 2007 there was approximately $6.0 million of unrecognized compensation cost related to non-vested restricted units. The cost is expected to be recognized over a weighted average period of approximately 2.1 years. Our consolidated statement of operations reflects non-cash compensation of

F-13

Vanguard Natural Resources, LLC and Subsidiaries
Notes to Consolidated Financial Statements (Continued)
For the Six Months Ended June 30, 2007
(Unaudited)

7. Unit-Based Compensation (Continued)

$0.6 million in the selling, general and administrative line item for the quarter and six months ended June 30, 2007.

8. Subsequent Events

In July 2007, a new borrowing base notice was received pursuant to our Credit Facility agreement which reaffirmed our $115.5 million borrowing base but required $1 million monthly reductions beginning on July 1, 2007 through the next redetermination date, which is October 1, 2007, at which time a new redetermination will be made.

In August 2007, a total of 55,000 restricted VNR Class B units, subject to vesting over three years from the date of grant, were issued to two employees that were hired in April and May of 2007. These Class B units were granted as partial consideration for services to be performed and thus will be subject to accounting for these grants under SFAS No. 123(R), Share-Based Payment.

F-14

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Members of
Vanguard Natural Gas, LLC
and Subsidiaries

We have audited the accompanying consolidated balance sheet of Vanguard Natural Gas, LLC (formerly Nami Holding Company, LLC), and subsidiaries (the “Company”) as of December 31, 2006, and the related consolidated statements of operations, members’ equity, and cash flows for the year then ended. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audit.

We conducted our audit 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 consolidated financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Vanguard Natural Gas, LLC and subsidiaries as of December 31, 2006, and the consolidated results of their operations and their cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America.

/s/ UHY LLP

Houston, Texas
April 20, 2007

F-15

CERTIFIED PUBLIC
ACCOUNTANTS

BUSINESS ADVISORS

TECHNOLOGY
CONSULTANTS

Report of Independent Registered Public Accounting Firm

To the Members
Vanguard Natural Gas, LLC
104 Nami Plaza, Suite 1
London, Kentucky 40741

1729 Midpark Road
Suite C-zoo
Knoxville, TN 37921

865.583.0091 phone
865.583.0560 fax

www.rodefermoss.com

We have audited the accompanying consolidated balance sheets of Vanguard Natural Gas, LLC (formerly Nami Holding Company, LLC) as of December 31, 2005 and 2004 and the related consolidated statements of operations, changes in members’ equity and cash flows for the years then ended. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated 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 audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. The Company has determined that it is not required to have, nor were we engaged to perform, an audit of the Company’s 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, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Vanguard Natural Gas, LLC as of December 3 1, 2005 and 2004, and the results of its operations and cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America.

Knoxville, Tennessee
April 3, 2007

GREENEVILLE - KNOXVILLE - NASHVILLE - TRI-CITIES

F-16

Vanguard Natural Gas, LLC and Subsidiaries
Consolidated Balance Sheet
As of December 31,

	2006			2005
Assets
Current assets
Cash and cash equivalents	$	1,730,956		$	3,041,468
Trade accounts receivable	5,269,067			6,903,469
Receivables due from affiliates (Note 7)	14,650,936			11,202,113
Other receivables (Note 2)	234,456			1,238,920
Inventory	106,359			51,371
Other current assets	177,525			202,760
Total current assets	22,169,299			22,640,101
Property and equipment
Land	46,350			11,350
Buildings	10,850			26,420
Furniture and fixtures	846,580			793,982
Machinery and equipment	12,681,363			4,291,300
Less: accumulated depreciation	(1,712,535		)	(1,019,402		)
Total property and equipment	11,872,608			4,103,650
Natural gas and oil properties, net - full cost method (Note 3)	104,683,610			83,512,700
Total Assets	$	138,725,517		$	110,256,451
Liabilities and members’ equity
Current liabilities
Accounts payable - trade	$	8,756,937		$	5,295,621
Accounts payable - natural gas and oil	1,441,941			4,529,876
Derivative contracts (Note 5)	2,022,079			11,527,103
Accrued expenses	1,230,686			2,132,871
Due to member (Note 7)	75,000			75,000
Total current liabilities	13,526,643			23,560,471
Long-term debt (Note 4)	94,067,500			72,707,500
Derivative contracts (Note 5)	—			8,242,793
Asset retirement obligations (Note 6)	418,533			212,588
Total liabilities	108,012,676			104,723,352
Commitments and contingencies (Note 8)
Members’ equity	30,712,841			5,533,099
Total liabilities and members’ equity	$	138,725,517		$	110,256,451

See accompanying notes to consolidated financial statements.

F-17

Vanguard Natural Gas, LLC and Subsidiaries
Consolidated Statement of Operations
For the Years Ended December 31,

	2006			2005			2004
Revenues
Natural gas and oil sales	$	38,184,473		$	40,299,286		$	23,881,231
Realized losses from derivative contracts	(2,207,902		)	(10,024,178		)	(5,925,619		)
Change in fair value of derivative contracts	17,747,817			(18,778,983		)	(990,914		)
Other	664,669			450,803			28,713
Total revenues	54,389,057			11,946,928			16,993,411
Costs and expenses
Lease operating expenses	4,896,327			4,607,198			2,406,528
Depreciation, depletion and amortization	8,633,235			6,189,478			4,029,279
Selling, general and administrative	5,198,760			5,945,613			3,153,838
Taxes other than income	1,774,215			1,248,946			611,208
Total costs and expenses	20,502,537			17,991,235			10,200,853
Income (loss) from operations	33,886,520			(6,044,307		)	6,792,558
Other income (expense)
Interest income	40,256			51,471			6,573
Interest expense	(7,371,930		)	(4,565,712		)	(1,454,809		)
Total other expense	(7,331,674		)	(4,514,241		)	(1,448,236		)
Net income (loss)	$	26,554,846		$	(10,558,548	)	$	5,344,322

See accompanying notes to consolidated financial statements.

F-18

Vanguard Natural Gas, LLC and Subsidiaries
Consolidated Statement of Members’ Equity
For the Years Ended December 31,

Balance, January 1, 2004	$	16,846,095
Net income	5,344,322
Members’ distribution	(1,279,437		)
Balance, December 31, 2004	$	20,910,980
Net loss	(10,558,548		)
Members’ distribution	(4,819,333		)
Balance, December 31, 2005	$	5,533,099
Net income	26,554,846
Members’ distribution	(1,375,104		)
Balance, December 31, 2006	$	30,712,841

See accompanying notes to consolidated financial statements.

F-19

Vanguard Natural Gas, LLC and Subsidiaries
Consolidated Statement of Cash Flows
For the Years Ended December 31,

	2006			2005			2004
Operating activities
Net income (loss)	$	26,554,846		$	(10,558,548	)	$	5,344,322
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	8,633,235			6,189,478			4,029,279
Change in fair value of derivative contracts	(17,747,817		)	18,778,983			990,914
Changes in operating assets and liabilities:
Trade accounts receivable	1,634,402			(127,911		)	(3,755,145		)
Receivables due from affiliates	(3,448,823		)	(8,488,293		)	(161,411		)
Other receivables	1,004,464			(989,545		)	235,008
Inventory	(54,988		)	(51,371		)	234,815
Other current assets	40,803			91,098			(112,933		)
Accounts payable	373,381			6,638,940			967,309
Accrued expenses	(902,185		)	(952,988		)	1,834,662
Net cash provided by operating activities	16,087,318			10,529,843			9,606,820
Investing activities
Additions to property and equipment	(8,486,055		)	(2,694,185		)	(662,824		)
Additions to natural gas and oil properties	(28,896,671		)	(34,373,612		)	(18,934,798		)
Net cash used in investing activities	(37,382,726		)	(37,067,797		)	(19,597,622		)
Financing activities
Proceeds from borrowings	21,360,000			30,390,000			14,000,000
Distribution to members	(1,375,104		)	(4,819,333		)	(1,279,437		)
Net cash provided by financing activities	19,984,896			25,570,667			12,720,563
Net increase (decrease) in cash and cash equivalents	(1,310,512		)	(967,287		)	2,729,761
Cash and cash equivalents, beginning of year	3,041,468			4,008,755			1,278,994
Cash and cash equivalents, end of year	$	1,730,956		$	3,041,468		$	4,008,755
Supplemental cash flow information:
Cash paid for interest	$	7,233,549		$	5,735,952		$	1,563,793
Non-cash financing and investing activities:
Asset retirement obligations	$	187,638		$	69,900		$	44,284

See accompanying notes to consolidated financial statements.

F-20

Vanguard Natural Gas, LLC and Subsidiaries
Notes to the Consolidated Financial Statements

1. Summary of Significant Accounting Policies

Basis of Presentation and Nature of Operations

These consolidated financial statements include the accounts of Vanguard Natural Gas, LLC formerly known as Nami Holding Company, LLC (“VNG”), and its wholly-owned subsidiaries; Nami Resource Company, LLC (“Nami Resources”), Trust Energy Company, LLC, (“TEC”) and Ariana Energy, LLC, (“Ariana Energy”). All significant intercompany accounts and transactions have been eliminated in the consolidated financial statements. Certain prior year amounts have been reclassified to conform to the current year presentation.

VNG was formed in Kentucky on December 15, 2004 and its principal business is to hold interests in Nami Resources, TEC and Ariana Energy.

Nami Resources was formed in Kentucky on August 6, 2000 and its principal business consists of natural gas and oil development and exploitation of mature, long-lived natural gas and oil properties which includes the operation and maintenance of its own pipeline gathering system and related property management in the Appalachian region of eastern Kentucky and Tennessee.

VNG, Nami Resources, TEC, and Ariana Energy are hereafter collectively referred to as “us”, “we”, “our” or “the Company”.

New Accounting Pronouncements Issued But Not Yet Adopted

In February 2006, the FASB issued SFAS No. 155, Accounting for Certain Hybrid Financial Instruments (“SFAS 155”), which amends SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities (“SFAS 133”) and SFAS No. 140, Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities (“SFAS 140”). SFAS 155 simplifies the accounting for certain derivatives embedded in other financial instruments by allowing them to be accounted for as a whole if the holder elects to account for the whole instrument on a fair value basis. SFAS 155 also clarifies and amends certain other provisions of SFAS 133 and SFAS 140. SFAS 155 is effective for all financial instruments acquired, issued or subject to a remeasurement event occurring after January 1, 2007. We do not expect the adoption of SFAS 155 to have a material impact on our consolidated financial statements.

F-21

Vanguard Natural Gas, LLC and Subsidiaries
Notes to the Consolidated Financial Statements (Continued)

1. Summary of Significant Accounting Policies (Continued)

Recently Adopted Accounting Pronouncements

In December 2004, the FASB issued SFAS No. 123(R), Share-Based Payment, which revised SFAS No. 123, Accounting for Stock-Based Compensation and superseded APB Opinion No. 25, Accounting for Stock Issued to Employees and the related interpretations. SFAS 123(R) focuses on accounting for share-based payments for services provided by employee to employer. The statement requires companies to expense the fair value of employee stock options and other equity-based compensation at the grant date. The statement does not require a certain type of valuation model and either a binomial or Black-Scholes model may be used. We adopted SFAS 123(R) on January 1, 2006; however, the adoption did not have a financial impact on the Company as no share-based payment awards have been issued by the Company as of December 31, 2006. However, subsequent to December 31, 2006, share-based awards were granted (see Note 9. Subsequent Events).

Cash Equivalents

The Company considers all highly liquid short-term investments with original maturities of three months or less to be cash equivalents.

Accounts Receivable and Allowance for Doubtful Accounts

Accounts receivable are customer obligations due under normal trade terms and are presented on the consolidated balance sheet net of allowances for doubtful accounts. We establish provisions for losses on accounts receivable if we determine that we will not collect all or part of the outstanding balance. We regularly review collectibility and establish or adjust our allowance as necessary using the specific identification method. There are no allowances for doubtful accounts recorded against accounts receivable at December 31, 2006 and 2005.

Inventory

Inventory consists primarily of field supplies and is recorded at the lower of cost or market. The cost is determined using the first-in, first-out method.

Property and Equipment

Property and equipment is recorded at cost. Major property additions, replacements and betterments are capitalized, while maintenance and repairs that do not extend the useful life of an asset are expensed as

F-22

Vanguard Natural Gas, LLC and Subsidiaries
Notes to the Consolidated Financial Statements (Continued)

1. Summary of Significant Accounting Policies (Continued)

incurred. Depreciation is recorded using the straight-line method over the respective estimated useful lives of our assets.

The estimated useful lives of our property and equipment are as follows:

	Lives (Years)
Building		39
Furniture and fixtures		7
Machinery and equipment		3-20

Depreciation expense for the years ended December 31, 2006, 2005, and 2004 was $693,266, $485,121, and $248,543, respectively.

Natural Gas and Oil Properties

The full cost method of accounting is used to account for natural gas and oil properties. Under the full cost method, substantially all costs incurred in connection with the acquisition, development and exploration of natural gas and oil reserves are capitalized. These capitalized amounts include the costs of unproved properties, internal costs directly related to acquisitions, development and exploration activities, asset retirement costs and capitalized interest. Under the full cost method, both dry hole costs and geological and geophysical costs are capitalized into the full cost pool, which is subject to amortization and subject to ceiling test limitations as discussed below.

Capitalized costs associated with proved reserves are amortized over the life of the reserves using the unit of production method. Conversely, capitalized costs associated with unproved properties are excluded from the amortizable base until these properties are evaluated, which occurs on a quarterly basis. Specifically, costs are transferred to the amortizable base when properties are determined to have proved reserves. In addition, we transfer unproved property costs to the amortizable base when unproved properties are evaluated as being impaired and as exploratory wells are determined to be unsuccessful. Additionally, the amortizable base includes estimated future development costs, dismantlement, restoration and abandonment costs net of estimated salvage values, and geological and geophysical costs incurred that cannot be associated with unevaluated properties or prospects in which we own a direct interest.

Capitalized costs are limited to a ceiling based on the present value of future net revenues using end of period spot prices discounted at 10%, plus the lower of cost or fair market value of unproved properties. If the ceiling is not greater than or equal to the total capitalized costs, we are required to write-down capitalized costs to the ceiling. We perform this ceiling test calculation each quarter. Any required write-downs are included in the consolidated statement of operations as a ceiling test charge. Ceiling test calculations include the effects of derivative contracts. Ceiling test calculations exclude the estimated future cash outflows associated with asset retirement obligations related to proved developed reserves.

When we sell or convey interests in natural gas and oil properties, they reduce natural gas and oil reserves for the amount attributable to the sold or conveyed interest. We do not recognize a gain or loss on sales of natural gas and oil properties, unless those sales would significantly alter the relationship between capitalized costs and proved reserves. Sales proceeds on insignificant sales are treated as an adjustment to the cost of the properties.

F-23

Vanguard Natural Gas, LLC and Subsidiaries
Notes to the Consolidated Financial Statements (Continued)

1. Summary of Significant Accounting Policies (Continued)

Asset Retirement Obligations

On January 1, 2003, we adopted SFAS No. 143, Accounting for Asset Retirement Obligations which requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The associated asset retirement cost is capitalized as part of the carrying amount of the long-lived asset. Subsequently, the asset retirement cost is allocated to expense using a systematic and rational method over the assets useful life. Our recognized asset retirement obligation exclusively relates to the plugging and abandonment of natural gas and oil wells. Management periodically reviews the estimate of the timing of well abandonments as well as the estimated plugging and abandonment costs, which are discounted at the credit adjusted risk free rate of 8%. These retirement costs are recorded as a long-term liability on the consolidated balance sheet with an offsetting increase in natural gas and oil properties. An ongoing accretion expense is recognized for changes in the value of the liability as a result of the passage of time, which we record in depreciation, depletion and amortization expense in the consolidated statement of operations.

Impairment of Long-Lived Assets

We evaluate the carrying value of long-lived assets, other than investments in natural gas and oil properties, when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. For property and equipment used in operations, the determination of impairment is based upon expectations of undiscounted future cash flows, before interest, of the related asset. If the carrying value of the asset exceeds the undiscounted future cash flows, the impairment would be computed as the difference between the carrying value of the asset and the fair value.

Revenue Recognition and Gas Imbalances

We apply the sales method of accounting for natural gas and oil revenue. Under this method, revenues are recognized based on the actual volume of natural gas and oil sold to customers, net of any royalty interests owed on the sold product. In the movement of natural gas, it is common for differences to arise between the volume of gas contracted or nominated, and the volume of gas actually received or delivered. These variances or imbalances, are the result of certain attributes of the natural gas commodity and the industry itself. Consequently, the credit given by a pipeline for volumes received from producers may be different than volumes actually delivered by a pipeline. When all necessary information, such as the final pipeline statement for receipts and deliveries are available, the imbalances are resolved and adjustments to the trade accounts receivable or trade accounts payable is recorded as appropriate.

Concentration of Credit Risk

Financial instruments that potentially subject us to concentrations of credit risk consist principally of cash and cash equivalents, accounts receivable and derivative contracts. We control our exposure to credit risk associated with these instruments by (i) placing our assets and other financial interests with credit-worthy financial institutions and (ii) maintaining policies over credit extension that include the evaluation of customers’ financial condition and monitoring payment history, although we do not have collateral requirements.

At December 31, 2006 and 2005, the cash and cash equivalents are concentrated in one financial institution. We periodically assess the financial condition of this institution and believe that any possible credit risk is minimal. At December 31, 2006 and 2005, six and five customers comprised 90% and 79% of

F-24

Vanguard Natural Gas, LLC and Subsidiaries
Notes to the Consolidated Financial Statements (Continued)

1. Summary of Significant Accounting Policies (Continued)

our total trade accounts receivable, respectively. This concentration of customers may impact the overall exposure to credit risk in that the customers are in the energy industry and they may be similarly affected by changes in economic or other conditions. In addition, receivables due from affiliates represented 66% and 49% of total current assets at December 31, 2006 and 2005, respectively. We believe these receivables will be collected within one year.

Use of Estimates

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 assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The most significant estimates pertain to proved natural gas and oil reserves and related cash flow estimates used in impairment tests of natural gas and oil properties, the fair value of derivative contracts and asset retirement obligations, natural gas and oil revenues and expenses, as well as estimates of expenses related to depreciation, depletion and amortization. Actual results could differ from those estimates.

Price Risk Management Activities

From time to time, the Company enters into derivative contracts, such as natural gas swaps, as a hedging strategy to manage commodity price risk associated with its production. Gains and losses on these hedging activities are generally recognized over the period that its production is hedged as an offset to the specific hedged item. Cash flows related to any recognized gains and losses associated with these hedges are reported as cash flows from operations. Changes in derivative fair values that are designated as hedges are deferred in accumulated other comprehensive income (loss) to the extent that they are effective and then recognized in operating revenues when the hedged transactions occur. The ineffective portion of a hedge’s change in value and the change in value of all derivative contracts not designated as hedges is recognized immediately in earnings as a separate line item in our consolidated statement of operations.

We record all derivative contracts on the consolidated balance sheet at fair value as either short-term or long-term assets or liabilities based upon their anticipated settlement date. The derivative contracts entered into in 2006, 2005 and 2004 were not specifically designated as hedges under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities and therefore did not qualify for hedge accounting treatment. The change in fair value of these derivative contracts is recorded in the consolidated statement of operations.

Income Taxes

No provision for income taxes has been made as the Company is considered a pass-through entity and is not subject to federal or state income taxes.

F-25

Vanguard Natural Gas, LLC and Subsidiaries
Notes to the Consolidated Financial Statements (Continued)

2. Other Receivables

From time to time, we advance funds to third parties, primarily for the purpose of providing financing related to the purchase of drilling rigs or other related equipment. Amounts due from such parties amounted to $234,456 and $1,238,920 at December 31, 2006 and 2005, respectively.

These receivables are non-interest bearing and are due upon demand. Such amounts are periodically repaid as such parties complete services.

3. Natural Gas and Oil Properties

Natural gas and oil properties are comprised of the following:

December 31,	2006			2005
Natural gas and oil properties, at cost	$	128,811,908		$	99,719,335
Accumulated depletion	(24,128,298		)	(16,206,635		)
Natural gas and oil properties, net	$	104,683,610		$	83,512,700

During the years ended December 31, 2006, 2005 and 2004, we recorded depletion expense of $7,921,662, $5,691,824, and $3,773,303, respectively.

4. Credit Facilities and Long-Term Debt

Our credit facilities and long-term debt consisted of the following at December 31, 2006 and 2005:

	Interest		Maturity	Amount Outstanding
Description	Rate		Date	2006		2005
$75 million Senior Secured Revolver	Variable (see below)		January 31, 2007	$	63,067,500	$	47,707,500
$40 million TCW Senior Secured Notes	13	%	December 29, 2011	31,000,000		25,000,000
Total				$	94,067,500	$	72,707,500

$75 million Senior Secured Revolver

On June 30, 2003, we entered into a $75 million senior secured revolving credit facility with the Bank of Texas (“Senior Revolver”) which amended and restated in its entirety a loan agreement dated March 23, 2001. The Senior Revolver had an original maturity date of June 30, 2006 but was extended through amendments to January 31, 2007. The available credit line (“Borrowing Base”) is subject to adjustment from time to time but not less than on a semi-annual basis based on the projected discounted present value (as determined by independent petroleum engineers) of estimated future net cash flows from certain proved natural gas and oil reserves of the Company. At December 31, 2006, the Borrowing Base was $65 million. The Senior Revolver is secured by a mortgage lien on certain natural gas and oil properties, field equipment and accounts receivable, among other assets held by the Company. Interest rates under this credit facility are at the election of the Company based on Euro-Dollars (LIBOR) or Stated Rate (Prime) indications, plus a margin. The margin can range from Prime minus 0.25% to Prime plus 0.25% or LIBOR plus 1.875% to LIBOR plus 2.625% depending on borrowing base utilization. At December 31, 2006, our interest rate was 8.5%. The availability of borrowings is subject to various

F-26

Vanguard Natural Gas, LLC and Subsidiaries
Notes to the Consolidated Financial Statements (Continued)

4. Credit Facilities and Long-Term Debt (Continued)

conditions, which include compliance with the financial covenants and ratios required by the facility, absence of default under the facility and the continued accuracy of the representations and warranties contained in the facility. At December 31, 2006, the financial coverage ratios under the facility require that our debt to EBITDA (as defined in the loan agreement) ratio not exceed 4.0 to 1.0 and our current ratio (as defined in the loan agreement) not be less than 1.0 to 1.0. In addition, affiliate investments (as defined in the loan agreement) may not exceed $10 million.

On January 3, 2007, all amounts due under the Senior Revolver were repaid and a new long-term credit facility was established (see Note 9. Subsequent Events) and therefore amounts due under the Senior Revolver are reported on the balance sheet as a long-term obligation despite the maturity date falling within one year of December 31, 2006.

$40 million TCW Senior Secured Notes

On December 30, 2004, we entered into a $40 million Senior Secured Notes facility due to TCW Asset Management Company (the “TCW Notes”). The TCW Notes mature on December 29, 2011 and require quarterly interest payments at 13% per annum. The TCW Notes are secured by a mortgage lien on certain natural gas and oil properties. Prior to December 30, 2006, the availability of borrowings was subject to various conditions, which included compliance with the financial covenants and ratios required by the facility, absence of default under the facility and the continued accuracy of the representations and warranties contained in the facility. After December 30, 2006, no new borrowings were available. At December 31, 2006, the financial coverage ratios under the facility required that our collateral coverage ratio (as defined in the loan agreement) not be less than 1.2 to 1.0 and our current ratio (as defined in the loan agreement) not be less than 1.0 to 1.0. We can not borrow, repay, and reborrow under the facility. Optional prepayments were not permitted prior to December 31, 2006 and were subject to a range of penalties thereafter until December 31, 2008 at which point no prepayment penalties applied.

On January 3, 2007, all amounts due under the TCW Notes were repaid and a new credit facility was established (see Note 9. Subsequent Events).

F-27

Vanguard Natural Gas, LLC and Subsidiaries
Notes to the Consolidated Financial Statements (Continued)

5. Financial Instruments and Price Risk Management Activities

The following table presents the carrying amounts and estimated fair values of our financial instruments as of December 31:

	2006				2005
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Senior Revolver	$	63,067,500	$	63,067,500	$	47,707,500	$	47,707,500
TCW Notes	$	31,000,000	$	30,212,807	$	25,000,000	$	24,571,975
Net liabilities from price risk management activities	$	2,022,079	$	2,022,079	$	19,769,896	$	19,769,896

At December 31, 2006 and 2005, the carrying amounts reported on the consolidated balance sheet for cash and cash equivalents, accounts receivable and accounts payable approximate fair value due to their short-term nature. The estimated fair value of financial instruments is the amount at which the instrument could be exchanged currently between willing parties. The Company uses available marketing data and valuation methodologies to estimate the fair value of debt. This disclosure is presented in accordance with SFAS No. 107, Disclosure about Fair Value of Financial Instruments and does not impact the Company’s financial position, results of operations or cash flows. The Senior Revolver credit facility approximates fair value because this instrument bears interest at current market rates. We estimated the fair value of our debt with fixed interest rates based on the present value of the future payments on the TCW Notes using a discount rate equal to the treasury yield at the measurement date plus the implied margin at inception of the loan as no quoted market prices exist for the same or similar issues.

From time to time, the Company enters into natural gas swap agreements with counterparties to hedge price risk associated with a portion of its production. These derivatives are not held for trading purposes. Under these price swaps, the Company receives a fixed price on a notional quantity of natural gas in exchange for paying a variable price based on a market index, such as TECO natural gas futures. During 2006, natural gas swaps covered 2,673,000 MMBtu, fixing the sales price of this natural gas at an average of $6.29 per MMBtu.

At December 31, 2006, the Company had open natural gas price swap contracts covering its 2007 production as follows:

	Natural Gas Price Swaps
Contract period	Volume in MMBtu		Weighted Average Price
First quarter 2007		413,000		$	6.04
Second quarter 2007		637,000		$	6.04
Third quarter 2007		644,000		$	6.04
Fourth quarter 2007		644,000		$	6.04
Total 2007		2,338,000		$	6.04

The derivative contracts entered into in 2006 and 2005 were not specifically designated as hedges under SFAS No. 133 Accounting for Derivative Instruments and Hedging Activities and therefore did not qualify for hedge accounting treatment. These derivative contracts are recorded at fair value on the consolidated balance sheet as short-term and long-term liabilities based upon their anticipated settlement

F-28

Vanguard Natural Gas, LLC and Subsidiaries
Notes to the Consolidated Financial Statements (Continued)

5. Financial Instruments and Price Risk Management Activities (Continued)

date. The change in fair value of these derivative contracts is recorded in the consolidated statement of operations.

On January 3, 2007, the natural gas price swaps referred to above were terminated and new natural gas derivative contracts were put in place in conjunction with entering into a new credit facility (see Note 9. Subsequent Events).

6. Asset Retirement Obligations

The asset retirement obligations as of December 31 reported on our balance sheet in non-current liabilities and the changes in the asset retirement obligations for the year ended December 31, were as follows:

	2006		2005
Asset retirement obligation at January 1,	$	212,588	$	130,155
Liabilities added during the current period	50,496		69,900
Accretion expense	18,307		12,533
Revisions to estimated cash flows	137,142		—
Asset retirement obligation at December 31,	$	418,533	$	212,588

Accretion expense for the years ended December 31, 2006, 2005 and 2004 was $18,307, $12,533 and $7,433, respectively.

7. Related Party Transactions

At December 31, 2006 and 2005, amounts payable to our primary member were $75,000. We maintain relationships with several closely related companies that directly support us through administrative and operational services. The total cost for services performed by these affiliates was $1,270,256 and $1,975,780 for the years ended December 31, 2006 and 2005, respectively. The Company has also historically funded certain capital requirements of its affiliates. As of December 31, 2006 and 2005, receivables due from affiliates were $14,650,936 and $11,202,113, respectively. These companies are affiliated through common ownership with our primary member. Our primary member has personally guaranteed certain indebtedness of these companies. All of the related party balances at December 31, 2006, will be conveyed to another entity pursuant to a restructuring plan described in Note 9. Subsequent Events. In addition, as of the restructuring no additional funding of related parties will occur.

8. Commitments and Contingencies

The Company is a defendant in various legal proceedings arising in the normal course of our business. While the outcome and impact of such legal proceedings on the Company cannot be predicted with certainty, management does not believe that it is probable that the outcome of any action will have a material adverse effect on the Company’s consolidated financial position, results of operations or cash flow.

F-29

Vanguard Natural Gas, LLC and Subsidiaries
Notes to the Consolidated Financial Statements (Continued)

8. Commitments and Contingencies (Continued)

The Company leases certain equipment, office space and two planes under cancelable and non-cancelable leases with third parties and affiliated companies. Rent expense for the years ended December 31, 2006, 2005 and 2004 was $3,514,502, $2,333,017 and $1,355,860, respectively.

Future minimum rental commitments under non-cancelable operating leases in effect at December 31, 2006 are as follows:

Year	Amount
2007	$	2,670,225
2008	2,682,844
2009	2,663,574
2010	1,849,838
2011	1,450,287
Thereafter	5,960,305
Total	$	17,277,073

Other Commercial Commitments

At December 31, 2006, we have a commitment associated with our drilling activities. Our annual obligation under this arrangement is $7,741,921 in 2007, $7,439,253 in 2008, $1,295,763 in 2009 and no amounts thereafter.

Defined Contribution Plan

In October 2005, the Company adopted a defined contribution plan covering all of our employees. The Company makes discretionary contributions based on a percentage of each employee’s gross compensation. We are responsible for benefits accrued under this plan and allocate the related costs to its participants. During the year ended December 31, 2006, the Company contributed $39,379 to the plan. No contributions were made for the year ended December 31, 2005.

9. Subsequent Events

New Credit Facility

In January 2007, the Company entered into a new four year $200,000,000 reserve-based revolving credit facility (“Credit Facility”) with two banks. All outstanding debt under the TCW Notes (including an early payment penalty of $2,501,528) and the Senior Revolver were repaid with borrowings under the new Credit Facility. The available credit line (“Borrowing Base”) is subject to adjustment from time to time but not less than on a semi-annual basis based on the projected discounted present value (as determined by independent petroleum engineers) of estimated future net cash flows from certain proved natural gas and oil reserves of the Company. The initial Borrowing Base was set at $115.5 million and is secured by a first lien security interest in all of the Company’s natural gas and oil properties.

F-30

Vanguard Natural Gas, LLC and Subsidiaries
Notes to the Consolidated Financial Statements (Continued)

9. Subsequent Events (Continued)

	Borrowing Base Utilization Grid
Borrowing Base Utilization Percentage	£25	%	>25% £50	%	>50% £75	%	>75	%
Eurodollar Loans	1.375	%	1.500	%	1.750	%	2.00	%
ABR Loans	0.250	%	0.500	%	0.750	%	1.00	%
Commitment Fee Rate	0.250	%	0.375	%	0.375	%	0.50	%
Letter of Credit Fee	1.375	%	1.500	%	1.750	%	2.00	%

The Credit Agreement contains a number of customary covenants that require the Company to maintain certain financial ratios, limit the Company’s ability to incur additional debt, sell assets, create liens, or make certain distributions. In addition, the first $80 million of proceeds received from an equity infusion must be applied to the repayment of borrowings under the Credit Facility (“Equity Event”). If borrowings under the Credit Facility are not reduced by $80 million by July 1, 2007, then the applicable margin increases as follows:

Eurodollar Loans	3.00	%
ABR Loans	4.00	%
Commitment Fee Rate	0.50	%
Letter of Credit Fee	3.00	%

The Credit Agreement required the Company to enter into a commodity price hedge position establishing certain minimum fixed prices for anticipated future production equal to approximately 84% of the projected production from proved developed producing reserves from the second half of 2007 through 2011. Also, the Credit Agreement required that certain production put option contracts for the years 2007, 2008 and 2009 be put in place to create a price floor for anticipated production from new wells drilled. A summary of the derivative contracts entered into in January 2007 is as follows:

Swap Agreements

Contract Period	Volume in MMBtu		Weighted Average Price
July – December 2007		1,708,357		$	7.50
2008		3,016,134		$	8.14
2009		2,657,046		$	7.87
2010		2,387,640		$	7.53
2011		2,196,012		$	7.15

Put Option Contracts

Contract Period	Volume in MMBtu		Weighted Average Price
February – December 2007		1,356,480		$	7.50
2008		2,211,366		$	7.50
2009		1,840,139		$	7.50

F-31

Vanguard Natural Gas, LLC and Subsidiaries
Notes to the Consolidated Financial Statements (Continued)

9. Subsequent Events (Continued)

The Company paid $6,453,596 for the put option contracts referenced above. The Credit Agreement also required the Company to terminate all open natural gas swap agreements (see Note 5. Financial Instruments and Price Risk Management Activities) which resulted in the Company incurring swap termination fees of $2,419,830. Payments for the put option contracts and the swap termination fee were funded with borrowings under the Credit Facility.

In January 2007, the Company elected to enter into a NYMEX natural gas price collar contract for February through June 2007 production covering 1,500,000 MMBtu with a floor of $6.45 and a ceiling of $7.45.

In March 2007, the first amendment to the Credit Facility was executed. The amendment redefined the method to calculate a financial covenant to include the impact of acquisitions and divestitures. In addition, it clarified that the increase in the applicable margin commencing on July 1, 2007 would only continue until the Equity Event has occurred.

In April 2007, the second amendment to the Credit Facility was executed. The amendment redefined change of control to allow for the sale of common units to private investors more fully described below, recognized certain contract rights to receive 100% of the net proceeds, after deducting royalties paid to other parties, severance taxes, third-party transportation costs, costs incurred in the operation of wells and overhead costs, from the sale of production from certain producing oil and gas wells located within the Asher lease and more fully described the Nami Restructuring Plan referred to below.

Nami Restructuring Plan, Private Offering, and Grant of Class B Units

Effective January 5, 2007, we conveyed to Vinland Energy Eastern, LLC and its affiliates 60% of our predecessor’s working interest in the known producing horizons in approximately 95,000 gross acres in an area of mutual interest, 100% of our predecessor’s interest in an additional 125,000 undeveloped acres and certain coal bed methane rights located in the Appalachian Basin, the rights to any natural gas and oil located on our acreage at depths above and 100 feet below our deepest producing horizon, all of our property, plant and equipment assets and all of our employees except for two officers. We retained all of our proved producing wells and associated reserves. We also retained 40% of our predecessor’s working interest in the known producing horizons in the 95,000 gross acres in an area of mutual interest. In addition, in February 2007 we changed the name of our operating company from Nami Holding Company, LLC to Vanguard Natural Gas, LLC (“VNG”).

In April 2007, the sole member of VNG contributed all of the issued and outstanding common units in VNG to Vanguard Natural Resources, LLC (“VNR”) for 6,000,000 common units representing all of the issued and outstanding common units of VNR. The sole member then completed a private equity offering pursuant to which he sold 2,290,000 common units to certain private investors for $41.2 million. The net proceeds of this private equity offering were used to make a $37.2 million distribution to the sole member to repay borrowings and interest under the Credit Facility and for general limited liability company purposes.

Also, in April 2007, the sole member granted certain members of management 365,000 restricted Class B units in VNR which vest over two years. In addition, another 95,000 restricted VNR Class B units were reserved for issuance to other members of management as they are retained. These Class B units

F-32

Vanguard Natural Gas, LLC and Subsidiaries
Notes to the Consolidated Financial Statements (Continued)

were granted as partial consideration for services to be performed under employment contracts and thus will be subject to accounting for these grants under SFAS No. 123(R), Share-Based Payment.

10. Supplemental Natural Gas and Oil Information (unaudited)

We are an independent natural gas and oil company focused on the development and exploitation of mature, long-lived natural gas and oil properties in the United States.

Capitalized costs related to natural gas and oil producing activities and related accumulated depletion were as follows at December 31:

	2006			2005
Aggregate capitalized costs relating to natural gas and oil producing activities	$	128,811,908		$	99,719,335
Aggregate accumulated depletion	(24,128,298		)	(16,206,635		)
Net capitalized costs	$	104,683,610		$	83,512,700
FAS 143 asset retirement obligations	$	418,533		$	212,588

Costs incurred in natural gas and oil producing activities, whether capitalized or expensed, were as follows for the years ended December 31:

	2006		2005		2004
Development costs	$	37,467,066	$	37,023,753	$	19,527,032
Total cost incurred	$	37,467,066	$	37,023,753	$	19,527,032

The table above includes capitalized internal costs incurred in connection with the development of natural gas and oil reserves of $3,880,000, $1,071,584 and $527,428 in 2006, 2005 and 2004. Additionally, capitalized interest of $117,097, $1,170,240 and $108,983 for the years ended December 31, 2006, 2005 and 2004, respectively, are included in the table above.

In our December 31, 2006 reserve report, the amounts estimated to be spent in 2007, 2008 and 2009 to develop our proved undeveloped reserves are $28.0 million, $27.6 million and $11.3 million, respectively.

Net quantities of proved developed and undeveloped reserves of natural gas and oil and changes in these reserves at December 31, 2006, 2005 and 2004 are presented below. Information in these tables is based on reserve reports prepared by our independent petroleum engineers, Netherland, Sewell & Associates, Inc. for 2006, Schlumberger Data & Consulting Services for 2005 and Wright & Company, Inc. for 2004.

F-33

Vanguard Natural Gas, LLC and Subsidiaries
Notes to the Consolidated Financial Statements (Continued)

10. Supplemental Natural Gas and Oil Information (unaudited)

	Gas (in Mcf)		Oil (in Bbls)
Net proved reserves
January 1, 2004	68,863,680			53,219
Revisions of previous estimates	1,424,945			(16,539	)
Extensions and discoveries	6,128,434			11,918
Production	(2,852,567	)		(9,698	)
December 31, 2004	73,564,492			38,900
Revisions of previous estimates	31,072,849			431,344
Extensions and discoveries	6,842,125			10,937
Production	(3,789,185	)		(17,488	)
December 31, 2005	107,690,281			463,693
Revisions of previous estimates	(17,529,333	)		(106,630	)
Extensions and discoveries	8,205,425			18,623
Production	(4,181,708	)		(32,718	)
December 31, 2006	94,184,665			342,968
Proved developed reserves
December 31, 2004	39,377,430			38,900
December 31, 2005	53,900,263			246,595
December 31, 2006	48,166,327			249,329

Revisions of previous estimates of reserves are a result of changes in natural gas and oil prices, production costs, well performance and the reservoir engineer’s methodology. Changes in natural gas prices had a significant impact on proved reserves in 2005 and 2006. From December 31, 2004 to December 31, 2005, the revisions of previous estimates increased proved natural gas reserves by 31.1 Bcf principally due to a 66% increase in the natural gas price used on December 31, 2005 ($9.89 per MMbtu) compared to the price on December 31, 2005 ($5.96 per MMbtu). Conversely, from December 31, 2005 to December 31, 2006, the revisions of previous estimates for natural gas reduced proved reserves by 17.5 Bcf largely due to natural gas prices decreasing from $9.89 per MMbtu to $5.63 per MMbtu at the respective year ends.

There are numerous uncertainties inherent in estimating quantities of proved reserves, projecting future rates of production and projecting the timing of development expenditures, including many factors beyond our control. The reserve data represents only estimates. Reservoir engineering is a subjective process of estimating underground accumulations of natural gas and oil that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretations and judgment. All estimates of proved reserves are determined according to the rules prescribed by the SEC. These rules indicate that the standard of “reasonable certainty” be applied to proved reserve estimates. This concept of reasonable certainty implies that as more technical data becomes available, a positive, or upward, revision is more likely than a negative, or downward, revision. Estimates are subject to revision based upon a number of factors, including reservoir performance, prices, economic conditions and government restrictions. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revision of that estimate. Reserve estimates are often different from the quantities of natural gas and oil that are ultimately recovered. The meaningfulness of reserve estimates is highly dependent on the accuracy of the assumptions on which they were based. In general, the volume of production from natural gas and oil properties we own declines as reserves are depleted. Except to the extent we conduct successful development activities or acquire

F-34

Vanguard Natural Gas, LLC and Subsidiaries
Notes to the Consolidated Financial Statements (Continued)

10. Supplemental Natural Gas and Oil Information (unaudited)

additional properties containing proved reserves, or both, our proved reserves will decline as reserves are produced. There have been no major discoveries or other events, favorable or adverse, that may be considered to have caused a significant change in the estimated proved reserves since December 31, 2006.

Results of operations from producing activities were as follows for the years ended December 31:

	2006			2005			2004
Production revenues(1)	$	35,976,571		$	30,275,108		$	17,955,612
Production costs(2)	(6,670,542		)	(5,856,144		)	(3,017,736		)
Depreciation, depletion and amortization	(8,511,390		)	(6,075,293		)	(3,933,648		)
Results of operations from producing activities	$	20,794,639		$	18,343,671		$	11,004,228

(1) Production revenues include realized losses on derivative contracts.

(2) Production cost includes lease operating expenses and production related taxes, including ad valorem and severance taxes.

The standardized measure of discounted future net cash flows relating to our proved natural gas and oil reserves at December 31 is as follows (in thousands):

	2006			2005			2004
Future cash inflows	$	663,604		$	1,337,090		$	540,412
Future production costs	(192,520		)	(138,912		)	(67,481		)
Future development costs	(66,906		)	(76,945		)	(33,820		)
Future net cash flows	404,178			1,121,233			439,111
10% annual discount for estimated timing of cash flows	(255,357		)	(720,804		)	(266,064		)
Standardized measure of discounted future net cash flows	$	148,821		$	400,429		$	173,047

For the December 31, 2006 calculations in the preceding table, estimated future cash inflows from estimated future production of proved reserves were computed using year-end prices of $5.63 per MMBtu for natural gas, adjusted by field for energy content, and $57.75 per barrel of oil, adjusted for quality, transportation fees and a regional price differential. We may receive amounts different than the standardized measure of discounted cash flow for a number of reasons, including price changes and the effects of our hedging activities.

The following are the principal sources of change in our standardized measure of discounted future net cash flows (in thousands):

	Year Ended December 31,(1)
	2006			2005			2004
Sales and transfers, net of production costs	$	(29,306	)	$	(24,419	)	$	(14,938	)
Net changes in prices and production costs	(231,630		)	125,520			44,652
Extensions discoveries and improved recovery, less related costs	21,110			20,027			19,930
Changes in estimated future development costs	(24,336		)	(58,972		)	(30,754		)
Previously estimated development costs incurred during the period	37,467			37,024			19,527
Revision of previous quantity estimates	(31,726		)	144,471			3,774
Accretion of discount	40,043			17,305			14,249
Change in production rates, timing and other	(33,230		)	(33,574		)	(25,887		)
Net change	$	(251,608	)	$	227,382		$	30,553

(1) This disclosure reflects changes in the standardized measure calculation excluding the effects of hedging activities and there are no future income tax expenses because we are a non-taxable entity.

F-35

VANGUARD NATURAL RESOURCES, LLC.
UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS
BASIS OF PRESENTATION

The following unaudited pro forma consolidated financial statements give effect to a variety of transactions. In the case of the unaudited consolidated statement of operations for the year ended December 31, 2006 the following transactions are considered as if they occurred on January 1, 2006: (i) the conveyance of certain operations out of Vanguard Natural Gas, LLC, formerly Nami Holding Company, LLC (“Predecessor”), to various newly formed entities owned by the principal member of the Predecessor (collectively referred to as “Vinland”), (ii) the contribution of the Predecessor to Vanguard Natural Resources, LLC (“Vanguard”), (iii) the effect of a sale of Vanguard common units to private investors, (iv) the reserving for a grant of 420,000 Class B units to Vanguard management and 40,000 common units to future employees and/or directors following the completion of the initial public offering and (v) the effect of the initial public offering contemplated by this prospectus. The financial statements of Vanguard Natural Gas, LLC for periods prior to the conveyance of certain operations to Vinland are presented as the Predecessor.

In the case of the interim unaudited consolidated statement of operations for the six months ended June 30, 2007 and the unaudited pro forma consolidated balance sheet at June 30, 2007, since the transactions referred to in (i), (ii), and (iii) above occurred during the interim period they are already included in the reported historical amounts and do not require pro forma adjustments. The pro forma effects of the transactions in (iv) and (v) above are considered as if they occurred on June 30, 2007 for the unaudited pro forma balance sheet and January 1, 2007 for the unaudited consolidated statement of operations for the six months ended June 30, 2007.

The accompanying unaudited pro forma consolidated financial statements of Vanguard should be read together with the historical consolidated financial statements of Vanguard and it’s Predecessor included elsewhere in this prospectus. The pro forma financial statements have been prepared on the basis that Vanguard will be treated as a partnership for federal income tax purposes. The accompanying unaudited pro forma consolidated financial statements of Vanguard were derived by making certain adjustments to the historical consolidated financial statements of Vanguard and it’s Predecessor. The adjustments are based on currently available information and certain estimates and assumptions. Therefore, the actual adjustments may differ from the pro forma adjustments. However, management believes that the assumptions provide a reasonable basis for presenting the significant effects of the transactions as contemplated and that the pro forma adjustments give appropriate effect to those assumptions and are properly applied in the pro forma consolidated financial statements.

F-36

Unaudited Pro Forma Consolidated Balance Sheet
As of June 30, 2007

							Vanguard
	Vanguard			Pro Forma			Pro Forma
	Historical			Adjustments			As Adjusted
Assets
Current assets
Cash and cash equivalents	$	4,445,007					$	4,445,007
Trade accounts receivable, net	4,190,075						4,190,075
Derivative assets	3,355,539						3,355,539
Deferred offering costs	1,571,993			(1,571,993		)(a)	—
Other current assets	12,372						12,372
Total current assets	13,574,986			(1,571,993		)	12,002,993
Property and equipment
Land	—						—
Buildings	—						—
Furniture and fixtures	31,211						31,211
Machinery and equipment	—						—
Less: accumulated depreciation	(166		)				(166		)
Net property and equipment	31,045						31,045
Natural gas and oil properties, net—full cost method	101,610,952						101,610,952
Other assets
Derivative assets	3,277,563						3,277,563
Deferred financing costs	1,052,036						1,052,036
Other assets	455,883						455,883
Total assets	$	120,002,465		$	(1,571,993	)	$	118,430,472
Liabilities and members’ equity (deficit)
Current liabilities
Accounts payable—trade	$	1,729,104					$	1,729,104
Accounts payable—natural gas and oil	734,238						734,238
Payables to affiliates	2,267,650						2,267,650
Deferred swap liability	7,322,685			(7,322,685		)(a)	—
Accrued expenses	527,095						527,095
Total current liabilities	12,580,772			(7,322,685		)	5,258,087
Reserve-based credit facility	109,000,000			(94,377,315		)(a)	14,622,685
Derivative liabilities	4,048,588						4,048,588
Asset retirement obligations	435,638						435,638
Total liabilities	126,064,998			(101,700,000		)	24,364,998
Members’ equity (deficit)	(6,062,533		)	115,000,000		(a)	94,065,474
				(8,050,000		)(a)
				(2,571,993		)(a)
				(4,250,000		)(a)
Total liabilities and members’ equity	$	120,002,465		$	(1,571,993	)	$	118,430,472

See notes to unaudited pro forma consolidated financial statements

F-37

Unaudited Pro Forma Consolidated Statement of Operations
For the Year Ended December 31, 2006

				Conveyed							Financing
				Operations							Transactions			Vanguard
	Predecessor			Pro Forma				Vanguard			Pro Forma			Pro Forma
	Historical			Adjustments(c)				Pro Forma			Adjustments			As Adjusted
Revenues
Natural gas and oil sales	$	38,184,473			$	—		$	38,184,473		$	—		$	38,184,473
Realized losses from derivative contracts	(2,207,902		)					(2,207,902		)				(2,207,902		)
Change in fair value of derivative contracts	17,747,817							17,747,817						17,747,817
Other	664,669				(664,669		)	—						—
Total revenues	54,389,057				(664,669		)	53,724,388			—			53,724,388
Costs and expenses
Lease operating expenses	4,896,327				171,285			5,067,612						5,067,612
Depreciation, depletion and amortization	8,633,235				(706,465		)	7,926,770						7,926,770
Selling, general and administrative	5,198,760				(2,185,689		)	3,013,071			4,013,333		(b)	8,876,404
											1,850,000		(d)
Taxes other than income	1,774,215				(42,994		)	1,731,221						1,731,221
Total costs and expenses	20,502,537				(2,763,863		)	17,738,674			5,863,333			23,602,007
Income from operations	33,886,520				(2,099,194		)	35,985,714			(5,863,333		)	30,122,381
Other income (expense)
Interest income	40,256							40,256						40,256
Interest expense	(7,371,930		)					(7,371,930		)	7,371,930		(e)	—
Total other expense	(7,331,674		)		—			(7,331,674		)	7,371,930			40,256
Net income	$	26,554,846			$	(2,099,194	)	$	28,654,040		$	1,508,597		$	30,162,637
Computation of pro forma net income per common unit:
Pro forma net income per common unit (Note 3)														$	2.74
Pro forma common units outstanding														11,000,000

See notes to unaudited pro forma consolidated financial statements

F-38

Unaudited Pro Forma Consolidated Statement of Operations
For the Six Months Ended June 30, 2007

							Vanguard
	Vanguard			Pro Forma			Pro Forma
	Historical			Adjustments			As Adjusted
Revenues
Natural gas and oil sales	$	19,068,353		$	—		$	19,068,353
Realized losses from derivative contracts	(1,665,852		)				(1,665,852		)
Total revenues	17,402,501			—			17,402,501
Costs and expenses
Lease operating expenses	2,460,420						2,460,420
Depreciation, depletion and amortization	4,320,289						4,320,289
Selling, general and administrative	1,215,489			1,443,523		(b)	3,584,012
				925,000		(d)
Bad debt expense	1,007,458						1,007,458
Taxes other than income	890,992						890,992
Total costs and expenses	9,894,648			2,368,523			12,263,171
Income from operations	7,507,853			(2,368,523		)	5,139,330
Other income (expense)
Interest income	27,646						27,646
Interest expense	(4,419,814		)	3,724,515		(e)	(695,299		)
Loss on extinguishment of debt	(2,501,528		)				(2,501,528		)
Total other expense	(6,893,696		)	3,724,515			(3,169,181		)
Net income	$	614,157		$	1,355,992		$	1,970,149
Computation of pro forma net income per common unit:
Pro forma net income per common unit (Note 3)	$	0.06					$	0.18
Pro forma common units outstanding	11,000,000						11,000,000

See notes to unaudited pro forma consolidated financial statements

F-39

VANGUARD NATURAL RESOURCES, LLC.
NOTES TO UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS

Note 1. Basis of Presentation, the Offering and Other Transactions

The unaudited pro forma consolidated financial statements are based upon the annual audited historical consolidated financial statements of VNG, the Predecessor to Vanguard, and the unaudited consolidated financial statements of Vanguard for the six months ended June 30, 2007. The pro forma consolidated balance sheet adjustments have been prepared as if the transactions effected had taken place on June 30, 2007, and in the case of the pro forma consolidated statement of operations, the pro forma adjustments have been presented as if the transactions effected had taken place at the beginning of the period presented.

The unaudited pro forma consolidated statement of operations for the year ended December 31, 2006 gives effect to the following transactions:

· the retention by Vanguard of 100% of our interest in the producing wells and 100% of our interest in the related proved producing reserves and 40% of our interest in the proved undeveloped reserves on leases within an area of mutual interest (“AMI”);

· the conveyance of certain assets, liabilities, and oil and gas operations to Vinland related to, among other things, (i) leasehold interests and wells not included in the AMI, (ii) 60% of our interest in the proved undeveloped reserves on leases within the AMI, (iii) pipelines and compression used to transport natural gas (collectively referred to as “Midstream Operations”), and (iv) affiliate balances. Also, all of the Predecessor employees other than two of its officers were transferred to Vinland;

· the private placement of 2,290,000 common units to private investors for $41.22 million in April 2007 and the subsequent distribution of those proceeds to the principal member;

· the reserving for a grant of 460,000 Class B units to Vanguard management in April 2007 and the associated non-cash compensation expense assuming all of the units had been granted on January 1, 2006. ;

· the sale by Vanguard of 5,000,000 common units to the public in the initial public offering and the application of the proceeds more fully described below.

However, at June 30, 2007 the first three transactions referred to above are reflected in the historical consolidated financial statements of Vanguard as of and for the six months ended June 30, 2007. Accordingly, the pro forma consolidated financial statements as of and for the six months ended June 30, 2007 only give effect to granting the 420,000 Class B units, the granting of 40,000 common units to future employees and/or directors following the completion of the initial public offering and the sale by Vanguard of 5,000,000 common units to the public in the initial public offering and the application of the proceeds.

Upon completion of this offering, Vanguard anticipates incurring incremental selling, general and administrative expenses related to becoming a separate public entity (e.g., cost of Schedule K-1 and tax return preparation, annual and quarterly reports to unitholders, stock exchange listing fees, and registrar and transfer agent fees, etc) in an annual amount of approximately $1.85 million. The unaudited pro forma consolidated financial statements reflect these incremental selling, general and administrative expenses. On the other hand, all of the Predecessor employees other than two of its officers were transferred to Vinland, and therefore, all related employee costs amounting to $2,185,689 in 2006 will not be borne by Vanguard and is reflected as such in the unaudited pro forma consolidated financial statements.

F-40

VANGUARD NATURAL RESOURCES, LLC.
NOTES TO UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 1. Basis of Presentation, the Offering and Other Transactions (Continued)

Vanguard will reimburse Vinland $60 per well per month (in addition to normal third party operating costs) for operating our current natural gas and oil properties in Appalachia under a Management Services Agreement (“MSA”) which costs are reflected in our pro forma lease operating expenses. Also, Vinland will receive a $0.25 per mcf transportation fee on existing wells drilled at December 31, 2006 and $0.55 per mcf transportation fee on any new wells drilled subsequently in the AMI. This transportation fee only encompasses transporting the natural gas to third party pipelines at which point additional transportation fees to natural gas markets would apply. These transportation fees are outlined under a Gathering and Compression Agreement (“GCA”) with Vinland and are reflected in our pro forma lease operating expenses. The actual cost of these fees for the six months ended June 30, 2007, is reflected in the historical lease operating expenses.

Note 2. Pro Forma Adjustments and Assumptions

(a) Reflects the issuance and sale of 5,000,000 common units at an assumed initial offering price of $23 for total proceeds of $115,000,000. The application of proceeds are expected as follows:

Underwriting discount	$	8,050,000
Estimated remaining offering related expenses(1)	1,000,000
Repayment of borrowings under new credit facility	94,377,315
Deferred swap liability(2)	7,322,685
Estimated accrued distributions(3)	4,250,000
Total	$	115,000,000

(1) Reflects the estimated remaining offering related expenses to be incurred from July 1, 2007 through the completion of the public offering. Actual offering expenses incurred through June 30, 2007 of $1,571,993 plus the estimated remaining offering expenses of $1,000,000 reflected above (total of $2,571,993) is reflected as a pro forma adjustment to Members’ Equity on the pro forma unaudited consolidated balance sheet.

(2) Reflects the deferred payment for resetting our natural gas swap contracts for 2007, 2008 and 2009 at higher prices in May 2007. Based on the associated costs for the periods being hedged, we determined that the total cost of $7,300,000 should be reflected as a short-term derivative asset ($3,724,853) and a long-term derivative asset ($3,597,832) and are reflected as such on the unaudited balance sheet of Vanguard as of June 30, 2007.

(3) Reflects the payment of accrued distributions to the principal member, private investors, and management in conjunction with the completion of the initial public offering, of which $2,302,083 is attributable to Nami, $1,622,083 is attributable to the private investors and $325,834 is attributable to management unitholders. Pursuant to the terms of the private placement, all holders of units began accruing distributions upon the closing of the sale of common units to the private investors at a rate of $1.70 annually. When the initial public offering is completed, the accrued distribution will be paid to all parties. It is assumed that five months will lapse between the closing of the sale of common units to the private investors and the completion of the initial public offering.

F-41

VANGUARD NATURAL RESOURCES, LLC.
NOTES TO UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 2. Pro Forma Adjustments and Assumptions (Continued)

(b) Reflects the reserving for a grant of 460,000 Class B units to Vanguard management and the associated non-cash compensation expense assuming all of the units had been granted. Current management received 365,000 Class B units in April 2007 which were valued for compensation purposes at the fair market value of $18 per unit established by the private investor transaction which occurred on the same date as the grant The remaining 95,000 Class B units (of which 55,000 were granted in August 2007) were all valued at the assumed initial offering price of $23. We have assumed that the 365,000 Class B units vest over a 24 month period and that the remaining 95,000 units vest over a 36-month period resulting in total non-cash compensation expense of $8,755,000 or $4,013,333 annually. Due to management receiving 365,000 Class B units in April 2007, the historical consolidated statement of operations for the six months ended June 30, 2007 already includes a $563,143 non-cash compensation charge which is considered in the pro forma adjustment to that period.

(c) Reflects the conveyance of certain assets, liabilities, and oil and gas operations to Vinland related to (i) leasehold interests and wells not included in the AMI, (ii) 60% of our interest in the proved undeveloped reserves on leases within the AMI, (iii) Midstream Operations and (iv) affiliate balances. Also, all of the Predecessor employees, except two officers, were transferred to Vinland. Assets (ie. trade accounts receivable, inventory, property and equipment, etc) and liabilities (ie. accounts payable, accrued expenses, derivative contracts, asset retirement obligations, etc) were divided based on specific identification. As all producing properties were retained by Vanguard, all revenue (except for a small amount of other non-production related revenue) is reflected as Vanguard revenue in the pro forma consolidated statement of operations. Lease operating expenses were increased to reflect the new fees under the MSA and the GCA and reduced by the historical amounts that will be borne by Vinland to carry out the services under the MSA and the GCA. Depreciation, depletion and amortization was reduced for the depreciation on property and equipment conveyed to Vinland. Selling, general and administrative costs were reduced to reflect all the employee costs related to running the Appalachian operations that will be borne by Vinland. Taxes other than income remained largely unchanged as the severance and ad valorem taxes incurred were on the revenue and reserves retained by Vanguard.

(d) Reflects estimated additional incremental expenses associated with ongoing administration of Vanguard as a publicly held entity.

(e) Reflects the reduction of interest expense incurred on long-term debt as a result of the repayment of outstanding debt balances with the proceeds of the initial public offering.

Note 3. Pro Forma Net Income per Unit

Pro forma net income per unit is determined by dividing the pro forma net income available to the common unitholders by the number of common units expected to be outstanding at the closing of the initial public offering. For purposes of this calculation, we assumed that all units were outstanding since the beginning of the period presented.

F-42

VANGUARD NATURAL RESOURCES, LLC.
NOTES TO UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 4. Supplemental Natural Gas and Oil Information

The following information summarizes the net proved reserves of natural gas and oil and the present values thereof as of December 31, 2006 and March 31, 2007 for the properties retained by Vanguard. The following reserve information is based upon the reports of the independent petroleum consulting firms of Netherland, Sewell & Associates, Inc. and Schlumberger Data & Consulting Services.

Management believes the reserve estimates presented herein, prepared in accordance with generally accepted engineering and evaluation principles consistently applied, are reasonable. However, there are numerous uncertainties inherent in estimating quantities and values of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond our control. Reserve engineering is a subjective process of estimating the recovery from underground accumulations of oil and gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of the available data and of engineering and geological interpretation and judgment. Because all reserve estimates are to some degree speculative, the quantities of oil and gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future natural gas and oil prices may all differ from those assumed in these estimates. In addition, different reserve engineers may make different estimates of reserve quantities and cash flows based upon the same available data. Therefore, the Standardized Measure shown below represents estimates only and should not be construed as the current market value of the estimated natural gas and oil reserves attributable to Vanguard’s properties.

Estimated Quantities of Natural Gas and Oil Reserves

The following table sets forth certain data pertaining to our estimated proved and proved developed reserves atDecember 31, 2006 and March 31, 2007.

	December 31, 2006												March 31, 2007
	Historical				Conveyed Operations				Vanguard Pro Forma				Vanguard
	Oil (Bbls)		Gas (Mcf)		Oil (Bbls)		Gas (Mcf)		Oil (Bbls)		Gas (Mcf)		Oil (Bbls)		Gas (Mcf)
Proved Reserves
Beginning balance	463,693		107,690,281		141,113		34,963,515		322,580		72,726,766		286,793		64,314,393
Revisions of previous estimates	(106,630	)	(17,529,333	)	(84,938	)	(5,093,243	)	(21,692	)	(12,436,090	)	(29,232	)	823,011
Extensions and discoveries	18,623		8,205,425		—		—		18,623		8,205,425		—		1,108,783
Production	(32,718	)	(4,181,708	)	—		—		(32,718	)	(4,181,708	)	(1,219	)	(1,068,075	)
Ending balance	342,968		94,184,665		56,175		29,870,272		286,793		64,314,393		256,342		65,178,112
Proved Developed Reserves
Beginning balance	246,595		53,900,263		—		—		246,595		53,900,263		249,329		48,166,327
Ending balance	249,329		48,166,327		—		—		249,329		48,166,327		221,419		48,499,447

F-43

VANGUARD NATURAL RESOURCES, LLC.
NOTES TO UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 4. Supplemental Natural Gas and Oil Information (Continued)

Standardized Measure of Discounted Future Net Cash Flows

The Standardized Measure of discounted future net cash flows relating to estimated proved natural gas and oil reserves as of December 31, 2006 and March 31, 2007 is presented below:

	December 31, 2006 (in thousands)											March 31, 2007 (in thousands)
	Historical			Conveyed Operations				Vanguard Pro Forma				Vanguard
Future cash inflows	$	663,604			$	205,834			$	457,770			$	649,578
Future development costs	(66,906		)		(43,389		)		(23,517		)		(32,389		)
Future production expense	(192,520		)		(55,754		)		(136,766		)		(159,179		)
Future net cash flows	404,178				106,691				297,487				458,010
Discounted at 10% per year	(255,357		)		(78,764		)		(176,593		)		(278,180		)
Standardize measure of discounted future net cash flows	$	148,821			$	27,927			$	120,894			$	179,830

The Standardized Measure of discounted future net cash flows (discounted at 10%) from production of proved reserves was developed as follows:

1. An estimate was made of the quantity of proved reserves and the future periods in which they are expected to be produced based on year-end economic conditions.

2. In accordance with SEC guidelines, the reserve engineers’ estimates of future net revenues from our proved properties and the present value thereof are made using natural gas and oil sales prices in effect as of the dates of such estimate and are held constant throughout the life of the properties. Our estimated net proved reserves as of December 31, 2006 were determined using $5.63 per Mmbtu of natural gas and $57.75 per barrel of oil. Our estimated net proved reserves as of March 31, 2007 were determined using $7.73 per Mmbtu of natural gas and $55.74 per barrel of oil.

3. The future gross revenue streams were reduced by royalties, estimated future operating costs, and future development and abandonment costs, all of which were based on current costs.

4. The reserve reports reflect the pre-tax present value of proved reserves to be $120,893,700 at December 31, 2006 and $179,830,000 at March 31, 2007. SFAS No. 69 requires us to further reduce these estimates by an amount equal to the present value of estimated income taxes that may be payable by us in future years to arrive at the Standardized Measure of discounted future net cash flows. Vanguard is not subject to entity level income tax; rather, the income or loss of the partnership is included in the income tax returns of the unitholders.

F-44

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Members of

Vanguard Natural Resources, LLC

We have audited the accompanying balance sheet of Vanguard Natural Resources, LLC (the “Company”) as of March 31, 2007. This balance sheet is the responsibility of the Company’s management. Our responsibility is to express an opinion on this balance sheet based on our audit.

We conducted our audit 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 balance sheet is free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the balance sheet. An audit also includes 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 provides a reasonable basis for our opinion.

In our opinion, the balance sheet referred to above presents fairly, in all material respects, the financial position of Vanguard Natural Resources, LLC as of March 31, 2007 in conformity with accounting principles generally accepted in the United States of America.

/s/ UHY LLP

Houston, Texas

April 20, 2007

F-45

Vanguard Natural Resources, LLC
Balance Sheet
March 31, 2007

Assets
Current assets:
Cash	$	1,000
Total Assets	$	1,000
Members’ Equity
Members’ equity	$	1,000
Total Members’ Equity	$	1,000

See accompanying notes to balance sheet

F-46

Vanguard Natural Resources, LLC
Notes to Balance Sheet
March 31, 2007

1. Organization

Vanguard Natural Resources, LLC (“Vanguard” or the “Company”) is a Delaware limited liability company formed in October 2006 to acquire Vanguard Natural Gas, LLC (“VNG”) (formerly Nami Holding Company, LLC). In March 2007, Majeed S. Nami contributed $1,000 as the sole organizational member. There have been no other transactions involving the Company as of March 31, 2007.

2. Subsequent Events

In April 2007, the sole member of Vanguard Natural Gas, LLC (“VNG”) (formerly Nami Holding Company, LLC) contributed all of the issued and outstanding common units in VNG to Vanguard for 6,000,000 common units representing all of the issued and outstanding common units of Vanguard. The sole member then completed a private equity offering pursuant to which he sold 2,290,000 common units to certain private investors for $41.2 million. The net proceeds of this private equity offering were used to make a $37.2 million distribution to the sole member to repay borrowings and interest under the Credit Facility and for general limited liability Company purposes.

Also, in April 2007, the sole member granted certain members of management 365,000 restricted Class B units in Vanguard which vest over two years. In addition, another 95,000 restricted Vanguard Class B units were reserved for issuance to other members of management as they are retained. These Class B units were granted as partial consideration for services to be performed under employment contracts and thus will be subject to accounting for these grants under SFAS No. 123(R), Share-Based Payment.

The Company intends to offer 5,000,000 common units, representing limited liability interests, pursuant to a public offering.

F-47

APPENDIX A

FORM OF

SECOND AMENDED AND RESTATED
LIMITED LIABILITY COMPANY AGREEMENT

VANGUARD NATURAL RESOURCES, LLC

TABLE OF CONTENTS

ARTICLE I
DEFINITIONS
Section 1.1	Definitions	A-1
Section 1.2	Construction	A-12
ARTICLE II
ORGANIZATION
Section 2.1	Formation	A-13
Section 2.2	Name	A-13
Section 2.3	Registered Office; Registered Agent; Principal Office; Other Offices	A-13
Section 2.4	Purposes and Business	A-13
Section 2.5	Powers	A-14
Section 2.6	Power of Attorney	A-14
Section 2.7	Term	A-15
Section 2.8	Title to Company Assets	A-15
ARTICLE III
RIGHTS OF MEMBERS
Section 3.1	Members	A-15
Section 3.2	Management of Business	A-16
Section 3.3	Outside Activities of the Members	A-16
Section 3.4	Rights of Members	A-16
ARTICLE IV
CERTIFICATES; RECORD HOLDERS;
TRANSFER OF INTERESTS; REDEMPTION OF INTERESTS
Section 4.1	Certificates	A-17
Section 4.2	Mutilated, Destroyed, Lost or Stolen Certificates	A-17
Section 4.3	Record Holders	A-18
Section 4.4	Transfer Generally	A-18
Section 4.5	Registration and Transfer of Member Interests	A-18
Section 4.6	Restrictions on Transfers	A-19
Section 4.7	Citizenship Certificates; Non-citizen Assignees	A-20
Section 4.8	Redemption of Member Interests of Non-citizen Assignees	A-21
ARTICLE V
CAPITAL CONTRIBUTIONS AND ISSUANCE OF INTERESTS
Section 5.1	Contributions by the Members; Issuance of Interests	A-22
Section 5.2	Interest and Withdrawal	A-23
Section 5.3	Capital Accounts	A-23
Section 5.4	Issuances of Additional Company Securities	A-25
Section 5.5	Limitations on Issuance of Additional Company Securities	A-25
Section 5.6	No Preemptive Rights	A-25
Section 5.7	Splits and Combinations	A-26
Section 5.8	Fully Paid and Non-Assessable Nature of Interests	A-26
Section 5.9	Special Provisions Relating to the Holders of Class B Units	A-26
Section 5.10	Registration Rights of Nami and Its Affiliates	A-27
Section 5.11	Conversion of the Class B Units	A-29

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ARTICLE VI
ALLOCATIONS AND DISTRIBUTIONS
Section 6.1	Allocations for Capital Account Purposes	A-30
Section 6.2	Allocations for Tax Purposes	A-33
Section 6.3	Requirement of Distributions; Distributions to Record Holders	A-36
Section 6.4	Distributions of Available Cash	A-36
ARTICLE VII
MANAGEMENT AND OPERATION OF BUSINESS
Section 7.1	Board of Directors	A-36
Section 7.2	Certificate of Formation	A-40
Section 7.3	Restrictions on the Board of Directors’ Authority	A-40
Section 7.4	Officers	A-41
Section 7.5	Outside Activities	A-42
Section 7.6	Loans or Contributions from the Company or Group Members	A-43
Section 7.7	Indemnification	A-43
Section 7.8	Exculpation of Liability of Indemnitees	A-45
Section 7.9	Resolution of Conflicts of Interest; Standards of Conduct and Modification of Duties	A-46
Section 7.10	Duties of Officers and Directors	A-47
Section 7.11	Purchase or Sale of Company Securities	A-48
Section 7.12	Reliance by Third Parties	A-48
ARTICLE VIII
BOOKS, RECORDS, ACCOUNTING AND REPORTS
Section 8.1	Records and Accounting	A-48
Section 8.2	Fiscal Year	A-48
Section 8.3	Reports	A-49
ARTICLE IX
TAX MATTERS
Section 9.1	Tax Returns and Information	A-49
Section 9.2	Tax Elections	A-49
Section 9.3	Tax Controversies	A-49
Section 9.4	Withholding	A-50
ARTICLE X
DISSOLUTION AND LIQUIDATION
Section 10.1	Dissolution	A-50
Section 10.2	Liquidator	A-50
Section 10.3	Liquidation	A-51
Section 10.4	Cancellation of Certificate of Formation	A-51
Section 10.5	Return of Contributions	A-51
Section 10.6	Waiver of Partition	A-51
Section 10.7	Capital Account Restoration	A-52
ARTICLE XI
AMENDMENT OF AGREEMENT; MEETINGS OF MEMBERS; RECORD DATE
Section 11.1	Amendment of Limited Liability Company Agreement	A-52
Section 11.2	Amendment Requirements	A-53
Section 11.3	Unitholder Meetings	A-54
Section 11.4	Notice of Meetings of Members	A-55

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Section 11.5	Record Date	A-55
Section 11.6	Adjournment	A-55
Section 11.7	Waiver of Notice; Approval of Meeting	A-55
Section 11.8	Quorum; Required Vote for Member Action; Voting for Directors	A-56
Section 11.9	Conduct of a Meeting; Member Lists	A-56
Section 11.10	Action Without a Meeting	A-57
Section 11.11	Voting and Other Rights	A-57
Section 11.12	Proxies and Voting	A-57
Section 11.13	Notice of Member Business and Nominations	A-58
ARTICLE XII
MERGER, CONSOLIDATION OR CONVERSION
Section 12.1	Authority	A-60
Section 12.2	Procedure for Merger, Consolidation or Conversion	A-60
Section 12.3	Approval by Members of Merger, Consolidation or Conversion	A-62
Section 12.4	Certificate of Merger; Certificate of Conversion	A-63
Section 12.5	Effect of Merger or Conversion	A-63
Section 12.6	Business Combination Limitations	A-64
ARTICLE XIII
RIGHT TO ACQUIRE MEMBER INTERESTS
Section 13.1	Right to Acquire Member Interests	A-64
ARTICLE XIV
GENERAL PROVISIONS
Section 14.1	Addresses and Notices	A-66
Section 14.2	Further Action	A-66
Section 14.3	Binding Effect	A-66
Section 14.4	Integration	A-66
Section 14.5	Creditors	A-66
Section 14.6	Waiver	A-66
Section 14.7	Counterparts	A-66
Section 14.8	Applicable Law	A-67
Section 14.9	Invalidity of Provisions	A-67
Section 14.10	Consent of Members	A-67

A-iii

SECOND AMENDED AND RESTATED LIMITED LIABILITY COMPANY
AGREEMENT OF VANGUARD NATURAL RESOURCES, LLC

This SECOND AMENDED AND RESTATED LIMITED LIABILITY COMPANY AGREEMENT OF VANGUARD NATURAL RESOURCES, LLC, dated as of , 2007 is entered into by and among Majeed S. Nami, Majeed S. Nami Irrevocable Trust dated 11. January 2007, Majeed S. Nami Personal Endowment Fund dated 11. January 2007, Nami Capital Partners, LLC, Scott W. Smith, Richard A. Robert, LEHMAN BROTHERS MLP OPPORTUNITY FUND L.P., a Delaware limited partnership, THIRD POINT PARTNERS LP, a Delaware limited partnership, THIRD POINT PARTNERS QUALIFIED LP, a Delaware limited partnership, BLRTQS Partner, a general partnership, Britt Pence, Patty Avila-Eady together with any other Persons who hereafter become Members in Vanguard Natural Resources, LLC or parties hereto as provided herein. In consideration of the covenants, conditions and agreements contained herein, the parties hereto hereby agree as follows:

ARTICLE I

DEFINITIONS

Section 1.1 Definitions. The following definitions shall be for all purposes, unless otherwise clearly indicated to the contrary, applied to the terms used in this Agreement.

“Accelerated Vesting Event” means, with respect to a particular Person, an event that results in the acceleration of the vesting of the Class B Units pursuant to any agreement, plan or arrangement, including any employment agreement, grant agreement or an employee benefit plan, pursuant to which Class B Units were granted to such Person.

“Additional Book Basis” means the portion of any remaining Carrying Value of an Adjusted Property that is attributable to positive adjustments made to such Carrying Value as a result of Book-Up Events. For purposes of determining the extent that Carrying Value constitutes Additional Book Basis:

(a) Any negative adjustment made to the Carrying Value of an Adjusted Property as a result of either a Book-Down Event or a Book-Up Event shall first be deemed to offset or decrease that portion of the Carrying Value of such Adjusted Property that is attributable to any prior positive adjustments made thereto pursuant to a Book-Up Event or Book-Down Event.

(b) If Carrying Value that constitutes Additional Book Basis is reduced as a result of a Book-Down Event and the Carrying Value of other property is increased as a result of such Book-Down Event, an allocable portion of any such increase in Carrying Value shall be treated as Additional Book Basis; provided that the amount treated as Additional Book Basis as a result of such Book-Down Event shall not exceed the amount by which the Aggregate Remaining Net Positive Adjustments after such Book-Down Event exceed the remaining Additional Book Basis attributable to all of the Company’s Adjusted Property after such Book-Down Event (determined without regard to the application of this clause (b) to such Book-Down Event).

“Additional Book Basis Derivative Items” means any Book Basis Derivative Items that are computed with reference to Additional Book Basis. To the extent that the Additional Book Basis attributable to all of the Company’s Adjusted Property as of the beginning of any taxable period exceeds the Aggregate Remaining Net Positive Adjustments as of the beginning of such period (the “Excess Additional Book Basis”), the Additional Book Basis Derivative Items for such period shall be reduced by the amount that bears the same ratio to the amount of Additional Book Basis Derivative Items determined without regard to this sentence as the Excess Additional Book Basis bears to the Additional Book Basis as of the beginning of such period.

“Additional Member” means a Person admitted as a Member of the Company pursuant to Section 4.5 and who is shown as such on the books and records of the Company.

A-1

“Adjusted Capital Account” means the Capital Account maintained for each Member as of the end of each fiscal year of the Company, (a) increased by any amounts that such Member is obligated to restore under the standards set by Treasury Regulation Section 1.704-1(b)(2)(ii)(c) (or is deemed obligated to restore under Treasury Regulation Sections 1.704-2(g) and 1.704-2(i)(5)) and (b) decreased by (i) the amount of all deductions in respect of depletion that, as of the end of such fiscal year are expected to be made to such Member’s Capital Account in respect of the oil and gas properties of the Company, (ii) the amount of all losses and deductions that, as of the end of such fiscal year, are reasonably expected to be allocated to such Member in subsequent years under Sections 704(e)(2) and 706(d) of the Code and Treasury Regulation Section 1.751-1(b)(2)(ii), and (iii) the amount of all distributions that, as of the end of such fiscal year, are reasonably expected to be made to such Member in subsequent years in accordance with the terms of this Agreement or otherwise to the extent they exceed offsetting increases to such Member’s Capital Account that are reasonably expected to occur during (or prior to) the year in which such distributions are reasonably expected to be made (other than increases as a result of a minimum gain chargeback pursuant to Section 6.1(d)(i) or Section 6.1(d)(ii)). The foregoing definition of Adjusted Capital Account is intended to comply with the provisions of Treasury Regulation Section 1.704-1(b)(2)(ii)(d) and shall be interpreted consistently therewith. The “Adjusted Capital Account” of a Member in respect of a Common Unit, a Class B Unit or any other Member Interest shall be the amount that such Adjusted Capital Account would be if such Common Unit, Class B Unit or other Member Interest were the only interest in the Company held by such Member from and after the date on which such Common Unit, Class B Unit or other Member Interest was first issued.

“Adjusted Property” means any property the Carrying Value of which has been adjusted pursuant to Section 5.3(d)(i) or Section 5.3(d)(ii).

“Affiliate” means, with respect to any Person, any other Person that directly or indirectly through one or more intermediaries controls, is controlled by or is under common control with the Person in question. As used herein, the term “control” means the possession, direct or indirect, of the power to direct or cause the direction of the management and policies of a Person, whether through ownership of voting securities, by contract or otherwise.

“Aggregate Remaining Net Positive Adjustments” means, as of the end of any taxable period, the sum of the Remaining Net Positive Adjustments of all Members.

“Agreed Allocation” means any allocation, other than a Required Allocation, of an item of income, gain, loss or deduction pursuant to the provisions of Section 6.1, including, without limitation, a Curative Allocation (if appropriate to the context in which the term “Agreed Allocation” is used).

“Agreed Value” of any Contributed Property means the fair market value of such property or other consideration at the time of contribution as determined by the Board of Directors. The Board of Directors shall use such method as it determines to be appropriate to allocate the aggregate Agreed Value of Contributed Properties contributed to the Company in a single or integrated transaction among each separate property on a basis proportional to the fair market value of each Contributed Property.

“Agreement” means this Second Amended and Restated Limited Liability Company Agreement of Vanguard Natural Resources, LLC, as it may be amended, supplemented or restated from time to time.

“Anniversary” has the meaning assigned to such term in Section 11.13(b).

“Assignee” means a Non-citizen Assignee or a person to whom one or more Member Interests have been transferred in a manner permitted under this Agreement but who has not been admitted as a Substitute Member.

“Associate” or “Associated” means, when used to indicate a relationship with any Person, (a) any corporation or organization of which such Person is a manager, director, officer or partner or is, directly or

A-2

indirectly, the owner of 20% or more of any class of voting stock or other voting interest; (b) any trust or other estate in which such Person has at least a 20% beneficial interest or as to which such Person serves as trustee or in a similar fiduciary capacity; and (c) any relative or spouse of such Person, or any relative of such spouse, who has the same principal residence as such Person.

“Available Cash” means, with respect to any Quarter ending prior to the Liquidation Date:

(a) the sum of:

(i) all cash and cash equivalents of the Company Group (or the Company’s proportionate share of cash and cash equivalents in the case of Subsidiaries that are not wholly owned) on hand at the end of that Quarter; and

(ii) all additional cash and cash equivalents of the Company Group (or the Company’s proportionate share of cash and cash equivalents in the case of Subsidiaries that are not wholly owned) on hand on the date of determination of Available Cash for that Quarter resulting from Working Capital Borrowings made subsequent to the end of such Quarter,

(b) less the amount of any cash reserves established by the Board of Directors (or the Company’s proportionate share of cash and cash equivalents in the case of Subsidiaries that are not wholly owned) to:

(i) provide for the proper conduct of the business of the Company Group (including reserves for future capital expenditures, including drilling and acquisitions, and for anticipated future credit needs of the Company Group),

(ii) comply with applicable law or any loan agreement, security agreement, mortgage, debt instrument or other agreement or obligation to which any Group Member is a party or by which it is bound or its assets are subject; or

(iii) provide funds for distributions under Section 6.4 with respect to any one or more of the next four Quarters;

provided that disbursements made by a Group Member or cash reserves established, increased or reduced after the end of that Quarter but on or before the date of determination of Available Cash for that Quarter shall be deemed to have been made, established, increased or reduced, for purposes of determining Available Cash, within that Quarter if the Board of Directors so determines.

Notwithstanding the foregoing, “Available Cash” with respect to the Quarter in which the Liquidation Date occurs and any subsequent Quarter shall equal zero.

“Board of Directors” has the meaning assigned to such term in Section 7.1(a).

“Book Basis Derivative Items” means any item of income, deduction, gain, loss, Simulated Depletion, Simulated Gain or Simulated Loss included in the determination of Net Income or Net Loss that is computed with reference to the Carrying Value of an Adjusted Property (e.g., depreciation, Simulated Depletion, or gain, loss, Simulated Gain or Simulated Loss with respect to an Adjusted Property).

“Book-Down Event” means an event that triggers a negative adjustment to the Capital Accounts of the Members pursuant to Section 5.3(d).

“Book-Tax Disparity” means, with respect to any item of Contributed Property or Adjusted Property, as of the date of any determination, the difference between the Carrying Value of such Contributed Property or Adjusted Property and the adjusted basis thereof for United States federal income tax purposes as of such date. A Member’s share of the Company’s Book-Tax Disparities in all of its Contributed Property and Adjusted Property will be reflected by the difference between such Member’s

A-3

Capital Account balance as maintained pursuant to Section 5.3 and the hypothetical balance of such Member’s Capital Account computed as if it had been maintained strictly in accordance with federal income tax accounting principles.

“Book-Up Event” means an event that triggers a positive adjustment to the Capital Accounts of the Members pursuant to Section 5.3(d).

“Business Day” means Monday through Friday of each week, except that a legal holiday recognized as such by the government of the United States of America or the State of New York shall not be regarded as a Business Day.

“Capital Account” means the capital account maintained for a Member pursuant to Section 5.3. The “Capital Account” of a Member in respect of a Unit or any Member Interest shall be the amount that such Capital Account would be if such Unit or other Member Interest were the only interest in the Company held by such Member from and after the date on which such Unit or other Member Interest was first issued.

“Capital Contribution” means any cash, cash equivalents or the Net Agreed Value of Contributed Property that a Member contributes to the Company.

“Carrying Value” means (a) with respect to a Contributed Property, the Agreed Value of such property reduced (but not below zero) by all depreciation, depletion (including Simulated Depletion), amortization and cost recovery deductions charged to the Members’ Capital Accounts in respect of such Contributed Property, and (b) with respect to any other Company property, the adjusted basis of such property for federal income tax purposes, all as of the time of determination. The Carrying Value of any property shall be adjusted from time to time in accordance with Section 5.3(d)(i) and Section 5.3(d)(ii) and to reflect changes, additions or other adjustments to the Carrying Value for dispositions and acquisitions of Company properties, as deemed appropriate by the Board of Directors.

“Certificate” means (a) a certificate (i) substantially in the form of (A) Exhibit A to this Agreement with respect to the Common Units and (B) a certificate, if any, in the form approved by the Board of Directors with respect to the Class B Units, (ii) issued in global form in accordance with the rules and regulations of the Depositary or (iii) in such other form as may be adopted by the Board of Directors, issued by the Company evidencing ownership of one or more Units or (b) a certificate, in such form as may be adopted by the Board of Directors, issued by the Company evidencing ownership of one or more other Company Securities.

“Certificate of Formation” means the Certificate of Formation of the Company filed with the Secretary of State of the State of Delaware as referenced in Section 7.2, as such Certificate of Formation may be amended, supplemented or restated from time to time.

“Chairman of the Board” has the meaning assigned to such term in Section 7.1.

“Citizenship Certification” means a properly completed certificate in such form as may be specified by the Board of Directors by which an Assignee or a Member certifies that he (and if he is a nominee holding for the account of another Person, that to the best of his knowledge such other Person) is an Eligible Citizen.

“Class B Member Interests” means the Member Interests represented by the Class B Units, which are intended to be and shall be treated as “profits interests” pursuant to Revenue Procedure 93-27 and Revenue Procedure 2001-43.

“Class B Unit” means a Unit representing a fractional part of the Membership Interests of all Members, and to the extent they are treated as Members hereunder, Assignees, having the rights and obligations specified with respect to Class B Units in this Agreement.

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“Closing Date” means the first date on which Common Units are sold by the Company to the Underwriters pursuant to the provisions of the Underwriting Agreement.

“Closing Price” has the meaning assigned to such term in Section 13.1.

“Code” means the United States Internal Revenue Code of 1986, as amended and in effect from time to time, as interpreted by the applicable regulations thereunder. Any reference herein to a specific section or sections of the Code shall be deemed to include a reference to any corresponding provision of any successor law.

“Commission” means the United States Securities and Exchange Commission.

“Common Units” means a Unit representing a fractional part of the Member Interests of all Members and, to the extent they are treated as Members hereunder, Assignees, and having the rights and obligations specified with respect to Common Units in this Agreement.

“Company” means Vanguard Natural Resources, LLC, a Delaware limited liability company, and any successors thereto.

“Company Group” means the Company and each Subsidiary of the Company, treated as a single consolidated entity.

“Company Minimum Gain” means that amount determined in accordance with the principles of Treasury Regulation Section 1.704-2(d).

“Company Security” means any class or series of equity interest in the Company (but excluding any options, rights, warrants and appreciation rights relating to an equity interest in the Company), including the Units.

“Conflicts Committee” means a committee of the Board of Directors composed entirely of one or more Independent Directors who are not (a) Officers or employees of the Company or any Subsidiary of the Company, (b) managers, directors, officers or employees of any Affiliate of the Company or (c) holders of any ownership interest in the Company Group other than Units.

“Contributed Property” means each property or other asset, in such form as may be permitted by the Delaware Act, but excluding cash, contributed to the Company. Once the Carrying Value of a Contributed Property is adjusted pursuant to Section 5.3(d), such property shall no longer constitute a Contributed Property, but shall be deemed an Adjusted Property.

“Credit Facility” means the Credit Facility dated as of January 3, 2007 among Nami Holding Company, LLC, Citibank, N.A. as Administrative Agent, various lenders named therein, Citibank, N.A. as Co-Lead Arranger, Sole Bookrunner and Co-Syndication Agent and BNP Paribas as Co-Lead Arranger and Co-Syndication Agent, as amended.

“Curative Allocation” means any allocation of an item of income, gain, deduction, loss or credit pursuant to the provisions of Section 6.1(d)(xi).

“Current Market Price” has the meaning assigned to such term in Section 13.1(a).

“Delaware Act” means the Delaware Limited Liability Company Act, 6 Del. C. Section 18-101, et seq., as amended, supplemented or restated from time to time, and any successor to such statute.

“Depositary” means, with respect to any Units issued in global form, The Depository Trust Company and its successors and permitted assigns.

“DGCL” means the General Corporation Law of the State of Delaware, 8 Del. C. Section 101, et seq., as amended, supplemented or restated from time to time, and any successor to such statute.

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“Director” means a member of the Board of Directors of the Company.

“Economic Risk of Loss” has the meaning set forth in Treasury Regulation Section 1.752-2(a).

“Eligible Citizen” means a Person qualified to own interests in real property in jurisdictions in which any Group Member does business or proposes to do business from time to time, and whose status as a Member or Assignee does not or would not subject such Group Member to a significant risk of cancellation or forfeiture of any of its properties or any interest therein.

“Exchange Act” means the Securities Exchange Act of 1934, as amended, supplemented or restated from time to time, and any successor for such statute.

“Final Adjudication” has the meaning assigned to such term in Section 7.7(c).

“First Amended and Restated Agreement” means the Amended and Restated Limited Liability Company Agreement of the Company dated as of April 18, 2007, which amended and restated the Limited Liability Company Agreement in its entirety and which is superseded in its entirety by this Agreement.

“Gathering Agreement” means that certain Gathering and Compression Agreement, dated as of April 18, 2007 but effective January 5, 2007, by and between the Company and Vinland Energy Gathering, LLC.

“Group” means a Person that with or through any of its Affiliates or Associates has any agreement, arrangement or understanding for the purpose of acquiring, holding, voting (except voting pursuant to a revocable proxy or consent given to such Person in response to a proxy or consent solicitation made to 10 or more Persons) exercising investment power or disposing of any Member Interests with any other Person that beneficially owns, or whose Affiliates or Associates beneficially own, directly or indirectly, Company Securities.

“Group Member” means a member of the Company Group.

“Group Member Agreement” means the partnership agreement of any Group Member, other than the Company, that is a limited or general partnership, the limited liability company agreement of any Group Member, other than the Company, that is a limited liability company, the certificate of incorporation and bylaws or similar organizational documents of any Group Member that is a corporation, the joint venture agreement or similar governing document of any Group Member that is a joint venture and the governing or organizational or similar documents of any other Group Member that is a Person other than a limited or general partnership, limited liability company, corporation or joint venture, as such may be amended, supplemented or restated from time to time.

“Indemnitee” means (a) any Person who is or was a Director, Officer or a Tax Matters Partner of the Company, (b) any Person who is or was a member, partner, manager, director, officer, fiduciary or trustee of any Group Member (other than the Company) or any Affiliate of a Group Member (other than the Company), (c) any Person who is or was serving at the request of the Company as a director, manager, officer, tax matters partner, fiduciary or trustee of another Person; provided that a Person shall not be an “Indemnitee” by reason of providing, on a fee-for-services basis, trustee, fiduciary or custodial services and (d) any Person that the Company designates as an “Indemnitee” for purposes of this Agreement.

“Independent Director” means a Director who meets the independence and other standards required of the members of the audit committee of a board of directors, which standards are established by the Exchange Act and the rules and regulations of the Commission thereunder and by the National Securities Exchange on which the Common Units are listed for trading.

“Initial Class B Holders” means Scott W. Smith, Richard A. Robert, Britt Pence and Patty Avila-Eady.

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“Initial Members” means Nami, Nami’s Trust, Nami Capital, Scott W. Smith, Richard A. Robert and each of the Private Investors, collectively.

“Initial Public Offering” means the initial public offering of Common Units by the Company that results in the Common Units being listed for trading on the New York Stock Exchange or the Nasdaq Global Market or any affiliate of the New York Stock Exchange or the Nasdaq Global Market.

“Initial Public Offering Documents” has the meaning assigned to such term in Section 7.1(k).

“Issue Price” means the price at which a Unit is purchased from the Company, after taking into account any sales commission or underwriting discount charged to the Company by the Underwriters.

“Limited Liability Company Agreement” means the Limited Liability Company Agreement of Vanguard Natural Resources, LLC, dated as of October 17, 2006, as amended through the date of this Agreement.

“Liquidation Date” means the date on which an event giving rise to the dissolution of the Company occurs.

“Liquidator” means one or more Persons selected by the Board of Directors to perform the functions described in Section 10.2 as liquidating trustee of the Company within the meaning of the Delaware Act.

“Management Services Agreement” means that certain Management Services and Development Agreement, dated as of April 18, 2007 but effective January 5, 2007, by and between the Company, Vinland Energy Operations, LLC and Vinland Energy Eastern, LLC.

“Member” means, unless the context otherwise requires, (a) each Initial Member, Initial Class B Holders, Substituted Member and Additional Member or (b) solely for purposes of Articles 5, 6, 7, 9, 11 and 12, each Assignee.

“Member Interest” means the ownership interest of a Member or Assignee in the Company, including Class B Member Interests, which may be evidenced by Units or other Company Securities or a combination thereof or interest therein, and includes any and all benefits to which such Member or Assignee is entitled as provided in this Agreement, together with all obligations of such Member or Assignee to comply with the terms and provisions of this Agreement.

“Member Nonrecourse Debt” has the meaning set forth with respect to “partner nonrecourse debt” in Treasury Regulation Section 1.704-2(b)(4).

“Member Nonrecourse Debt Minimum Gain” has the meaning set forth with respect to “partner nonrecourse minimum gain” in Treasury Regulation Section 1.704-2(i)(2).

“Member Nonrecourse Deductions” means any and all items of loss, deduction, expenditure (including any expenditure described in Section 705(a)(2)(B) of the Code), Simulated Depletion or Simulated Loss that, in accordance with the principles of Treasury Regulation Section 1.704-2(i), are attributable to a Member Nonrecourse Debt.

“Merger Agreement” has the meaning assigned to such term in Section 12.1.

“Nami” means Majeed S. Nami. Unless otherwise indicated, references in this Agreement to Common Units owned by Nami include the Common Units held by the Nami Trusts and Nami Capital, collectively.

“Nami Capital” means Nami Capital Partners, LLC, a Kentucky limited liability company.

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“Nami Trusts” means the Majeed S. Nami Irrevocable Trust dated January 11, 2007 and the Majeed S. Nami Personal Endowment Fund dated January 11, 2007, collectively

“National Securities Exchange” means an exchange registered with the Commission under Section 6(a) of the Securities Exchange Act of 1934, as amended, supplemented or restated from time to time, and any successor to such statute.

“Net Agreed Value” means, (a) in the case of any Contributed Property, the Agreed Value of such property reduced by any liabilities either assumed by the Company upon such contribution or to which such property is subject when contributed, and (b) in the case of any property distributed to a Member or Assignee by the Company, the Company’s Carrying Value of such property (as adjusted pursuant to Section 5.3(d)(ii)) at the time such property is distributed, reduced by any indebtedness either assumed by such Member or Assignee upon such distribution or to which such property is subject at the time of distribution, in either case, as determined under Section 752 of the Code.

“Net Income” means, for any taxable year, the excess, if any, of the Company’s items of income and gain (other than those items taken into account in the computation of Net Termination Gain or Net Termination Loss) for such taxable year over the Company’s items of loss and deduction (other than those items taken into account in the computation of Net Termination Gain or Net Termination Loss) for such taxable year. The items included in the calculation of Net Income shall be determined in accordance with Section 5.3(b) and shall include Simulated Gains, Simulated Losses, and Simulated Depletion, but shall not include any items specially allocated under Section 6.1(d).

“Net Loss” means, for any taxable year, the excess, if any, of the Company’s items of loss and deduction (other than those items taken into account in the computation of Net Termination Gain or Net Termination Loss) for such taxable year over the Company’s items of income and gain (other than those items taken into account in the computation of Net Termination Gain or Net Termination Loss) for such taxable year. The items included in the calculation of Net Loss shall be determined in accordance with Section 5.3(b) and shall include Simulated Gains, Simulated Losses, and Simulated Depletion, but shall not include any items specially allocated under Section 6.1(d).

“Net Positive Adjustments” means, with respect to any Member, the excess, if any, of the total positive adjustments over the total negative adjustments made to the Capital Account of such Member pursuant to Book-Up Events and Book-Down Events.

“Net Termination Gain” means, for any taxable year, the sum, if positive, of all items of income, gain, loss or deduction recognized by the Company after the Liquidation Date. The items included in the determination of Net Termination Gain shall be determined in accordance with Section 5.3(b) and shall include Simulated Gains, Simulated Losses and Simulated Depletion, but shall not include any items of income, gain or loss specially allocated under Section 6.1(d).

“Net Termination Loss” means, for any taxable year, the sum, if negative, of all items of income, gain, loss or deduction recognized by the Company after the Liquidation Date. The items included in the determination of Net Termination Loss shall be determined in accordance with Section 5.3(b) and shall include Simulated Gains, Simulated Losses and Simulated Depletion, but shall not include any items of income, gain or loss specially allocated under Section 6.1(d).

“Non-citizen Assignee” means a Person whom the Board of Directors has determined does not constitute an Eligible Citizen pursuant to Section 4.7.

“Nonrecourse Built-in Gain” means with respect to any Contributed Properties or Adjusted Properties that are subject to a mortgage or pledge securing a Nonrecourse Liability, the amount of any taxable gain that would be allocated to the Members pursuant to Section 6.2(d)(i)(A),

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Section 6.2(d)(ii)(A) and Section 6.2(d)(iii) if such properties were disposed of in a taxable transaction in full satisfaction of such liabilities and for no other consideration.

“Nonrecourse Deductions” means any and all items of loss, deduction, expenditure (including any expenditure described in Section 705(a)(2)(B) of the Code), Simulated Depletion or Simulated Loss that, in accordance with the principles of Treasury Regulation Section 1.704-2(b), are attributable to a Nonrecourse Liability.

“Nonrecourse Liability” has the meaning set forth in Treasury Regulation Section 1.752-1(a)(2).

“Notice of Election to Purchase” has the meaning assigned to such term in Section 13.1(b).

“Officer” has the meaning assigned to such term in Section 7.4(a).

“Operating Company” means Vanguard Natural Gas, LLC (formerly Nami Holding Company, LLC) and any successors thereto.

“Opinion of Counsel” means a written opinion of counsel (who may be regular counsel to the Company or any of its Affiliates) acceptable to the Board of Directors.

“Option Closing Date” means the date or dates on which any Common Units are sold by the Company to the Underwriters upon exercise of the Over-Allotment Option.

“Organizational Member” means Majeed S. Nami, in his capacity as the organizational member of the Company.

“Outstanding” means, with respect to Company Securities, all Company Securities that are issued by the Company and reflected as outstanding on the Company’s books and records as of the date of determination; provided, however, that (i) no Company Securities held by the Company (other than Company Securities representing Member Interests held by the Company on behalf of Non-Citizen Assignees) or any other Group Member shall be considered Outstanding and (ii) if at any time any Person or Group (other than Nami or its Affiliates) beneficially owns 20% or more of any Outstanding Company Securities of any class then Outstanding, all Company Securities owned by such Person or Group shall not be voted on any matter and shall not be considered to be Outstanding when sending notices of a meeting of Members to vote on any matter (unless otherwise required by law), calculating required votes, determining the presence of a quorum or for other similar purposes under this Agreement, provided that the foregoing limitation shall not apply to any Person or Group who acquired 20% or more of any Outstanding Company Securities of any class then Outstanding directly from the Company, Nami or its Affiliates with the prior approval of the Board of Directors including, solely with respect to the Common Units acquired pursuant to the Purchase Agreement, the Private Investors.

“Over-Allotment Option” means the over-allotment option granted to the Underwriters by the Company pursuant to the Underwriting Agreement.

“Per Unit Capital Account” means as of any date of determination, the Capital Account stated on a per Unit basis underlying any Unit held by any Person.

“Percentage Interest” means, as of any date of determination (a) as to any Unitholder holding Units, the product obtained by multiplying (i) 100% less the percentage applicable to paragraph (b) by (ii) the quotient obtained by dividing (A) the number of Units held by such Unitholder by (B) the total number of all Outstanding Units, and (b) as to the holders of other Company Securities issued by the Company in accordance with Section 5.4, the percentage established as a part of such issuance.

“Person” means an individual or a corporation, limited liability company, partnership, joint venture, trust, unincorporated organization or other enterprise (including an employee benefit plan), association, government agency or political subdivision thereof or other entity.

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“Prime Rate” means the prime rate of interest as quoted from time to time by the Wall Street Journal or another source reasonably selected by the Company.

“Private Investors” means each Person named as a purchaser in Schedule I to the Purchase Agreement who purchased Common Units pursuant thereto.

“Pro Rata” means (a) when modifying Units or any class thereof, apportioned equally among all such Units in accordance with their relative Percentage Interests, and (b) when modifying Members, apportioned among all designated Members in accordance with their relative Percentage Interest.

“Purchase Agreement” means the Purchase Agreement dated April 18, 2007, among the Private Investors, the Company and Nami providing for the purchase of Common Units from the Company by the Private Investors.

“Purchase Date” means the date determined by the Board of Directors as the date for purchase of all Outstanding Units of a certain class pursuant to Article XIII.

“Quarter” means, unless the context requires otherwise, a fiscal quarter, or, with respect to the first fiscal quarter after the Closing Date, the portion of such fiscal quarter after the Closing Date, of the Company.

“Recapture Income” means any gain recognized by the Company (computed without regard to any adjustment required by Section 734 or Section 743 of the Code) upon the disposition of any property or asset of the Company, which gain is characterized as ordinary income because it represents the recapture of deductions previously taken with respect to such property or asset.

“Record Date” means the date established by the Company for determining (a) the identity of the Record Holders entitled to notice of, or to vote at, any meeting of Members or entitled to exercise rights in respect of any lawful action of Members or (b) the identity of Record Holders entitled to receive any report or distribution or to participate in any offer.

“Record Holder” means the Person in whose name a Unit is registered on the books of the Transfer Agent as of the opening of business on a particular Business Day, or with respect to other Company Securities, the Person in whose name any such other Company Security is registered on the books that the Company has caused to be kept as of the opening of business on such Business Day.

“Redeemable Interests” means any Member Interests for which a redemption notice has been given, and has not been withdrawn, pursuant to Section 4.8 or Section 4.10.

“Registration Statement” means the Registration Statement on Form S-1 (Registration No. 333-142363) as it has been or as it may be amended or supplemented from time to time, filed by the Company with the Commission under the Securities Act to register the offering and sale of the Common Units in the Initial Public Offering.

“Remaining Net Positive Adjustments” means as of the end of any taxable period, with respect to the Unitholders holding Common Units or Class B Units, the excess of (i) the Net Positive Adjustments of the Unitholders holding Common Units or Class B Units as of the end of such period over (ii) the sum of those Members’ Share of Additional Book Basis Derivative Items for each prior taxable period.

“Required Allocations” means (a) any limitation imposed on any allocation of Net Losses or Net Termination Losses under Section 6.1(b) or Section 6.1(c)(ii) and (b) any allocation of an item of income, gain, loss, deduction, Simulated Depletion or Simulated Loss pursuant to Section 6.1(d)(i), Section 6.1(d)(ii), Section 6.1(d)(iv), Section 6.1(d)(v), Section 6.1(d)(vii) or Section 6.1(d)(ix).

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“Residual Gain” or “Residual Loss” means any item of gain or loss or Simulated Gain or Simulated Loss, as the case may be, of the Company recognized for federal income tax purposes resulting from a sale, exchange or other disposition of a Contributed Property or Adjusted Property, to the extent such item of gain or loss or Simulated Gain or Simulated Loss is not allocated pursuant to Section 6.2(d)(i)(A) or 6.2(d)(ii)(A), respectively, to eliminate Book-Tax Disparities.

“Securities Act” means the Securities Act of 1933, as amended, supplemented or restated from time to time and any successor to such statute.

“Share of Additional Book Basis Derivative Items” means in connection with any allocation of Additional Book Basis Derivative Items for any taxable period, with respect to the Unitholders holding Common Units or Class B Units, the amount that bears the same ratio to such Additional Book Basis Derivative Items as the Unitholders’ Remaining Net Positive Adjustments as of the end of such period bears to the Aggregate Remaining Net Positive Adjustments as of that time.

“Simulated Basis” means the Carrying Value of any oil and gas property (as defined in Section 614 of the Code).

“Simulated Depletion” means, with respect to an oil and gas property (as defined in Section 614 of the Code), a depletion allowance computed in accordance with federal income tax principles (as if the Simulated Basis of the property were its adjusted tax basis) and in the manner specified in Treasury Regulation §1.704-1(b)(2)(iv)(k)(2). For purposes of computing Simulated Depletion with respect to any property, the Simulated Basis of such property shall be deemed to be the Carrying Value of such property, and in no event shall such allowance for Simulated Depletion, in the aggregate, exceed such Simulated Basis.

“Simulated Gain” means the excess of the amount realized from the sale or other disposition of an oil or gas property over the Carrying Value of such property.

“Simulated Loss” means the excess of the Carrying Value of an oil or gas property over the amount realized from the sale or other disposition of such property.

“Solicitation Notice” has the meaning assigned to such term in Section 11.13(c).

“Special Approval” means approval by a majority of the members of the Conflicts Committee.

“Subsidiary” means, with respect to any Person, (a) a corporation of which more than 50% of the voting power of shares entitled (without regard to the occurrence of any contingency) to vote in the election of directors or other governing body of such corporation is owned, directly or indirectly, at the date of determination, by such Person, by one or more Subsidiaries of such Person or a combination thereof, (b) a partnership (whether general or limited) in which such Person or a Subsidiary of such Person is, at the date of determination, a general or limited partner of such partnership, but only if more than 50% of the partnership interests of such partnership (considering all of the partnership interests of the partnership as a single class) is owned, directly or indirectly, at the date of determination, by such Person, by one or more Subsidiaries of such Person, or a combination thereof, or (c) any other Person (other than a corporation or a partnership) in which such Person, one or more Subsidiaries of such Person, or a combination thereof, directly or indirectly, at the date of determination, has (i) at least a majority ownership interest or (ii) the power to elect or direct the election of a majority of the directors or other governing body of such Person.

“Substituted Member” means a Person who is admitted as a Member of the Company pursuant to Sections 4.5 or 4.7 in place of and with all rights of a Member and who is shown as a Member on the books and records of the Company.

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“Surviving Business Entity” has the meaning assigned to such term in Section 12.2(b).

“Tax Matters Partner” means the Tax Matters Partner as defined in the Code.

“Trading Day” has the meaning assigned to such term in Section 13.1.

“Transfer” or “transfer” has the meaning assigned to such term in Section 4.4.

“Transfer Agent” means such bank, trust company or other Person (including the Company or one of its Affiliates) as shall be appointed from time to time by the Company to act as registrar and transfer agent for the Units; provided that if no Transfer Agent is specifically designated for any other Company Securities, the Company shall act in such capacity.

“Underwriters” means the underwriters in the Initial Public Offering.

“Underwriting Agreement” means that certain Underwriting Agreement dated , 2007, among the Underwriters, the Company and certain other parties, providing for the purchase of Common Units by the Underwriters.

“Unit” means a Company Security that is designated as a “Unit” and shall include Common Units and Class B Units.

“Unit Majority” means at least a majority of the Outstanding Common Units and Class B Units, voting together as a single class.

“Unitholders” means the holders of Units.

“Unrealized Gain” attributable to any item of Company property means, as of any date of determination, the excess, if any, of (a) the fair market value of such property as of such date (as determined under Section 5.3(d)) over (b) the Carrying Value of such property as of such date (prior to any adjustment to be made pursuant to Section 5.3(d) as of such date).

“Unrealized Loss” attributable to any item of Company property means, as of any date of determination, the excess, if any, of (a) the Carrying Value of such property as of such date (prior to any adjustment to be made pursuant to Section 5.3(d) as of such date) over (b) the fair market value of such property as of such date (as determined under Section 5.3(d)).

“U.S. GAAP” means United States generally accepted accounting principles consistently applied.

“Working Capital Borrowings” means borrowings used solely for working capital purposes or to pay distributions to Members made pursuant to a credit facility, commercial paper facility or other similar financing arrangement, provided that when it is incurred it is the intent of the borrower to repay such borrowings within 12 months from other than Working Capital Borrowings.

Section 1.2 Construction. Unless the context requires otherwise: (a) any pronoun used in this Agreement shall include the corresponding masculine, feminine or neuter forms, and the singular form of nouns, pronouns and verbs shall include the plural and vice versa; (b) references to Articles and Sections refer to Articles and Sections of this Agreement; and (c) the term “include” or “includes” means includes, without limitation, and “including” means including, without limitation.

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ARTICLE II

ORGANIZATION

Section 2.1 Formation. The Organizational Member has previously formed the Company as a limited liability company pursuant to the provisions of the Delaware Act and each of the Private Investors, Nami, Nami’s Trusts, Nami Capital, Scott W. Smith, Richard A. Robert, Britt Pence and Patty Avila-Eady hereby amends and restates the First Amended and Restated Agreement in its entirety. This amendment and restatement shall become effective on the date of this Agreement. Except as expressly provided to the contrary in this Agreement, the rights, duties (including fiduciary duties), liabilities and obligations of the Members and the administration, dissolution and termination of the Company shall be governed by the Delaware Act. All Member Interests shall constitute personal property of the owner thereof for all purposes and a Member has no interest in specific Company property.

Section 2.2 Name. The name of the Company shall be Vanguard Natural Resources, LLC. The Company’s business may be conducted under any other name or names, as determined by the Board of Directors. The words “Limited Liability Company,” “LLC,” or similar words or letters shall be included in the Company’s name where necessary for the purpose of complying with the laws of any jurisdiction that so requires. The Board of Directors may change the name of the Company at any time and from time to time and shall notify the Members of such change in the next regular communication to the Members.

Section 2.3 Registered Office; Registered Agent; Principal Office; Other Offices. Unless and until changed by the Board of Directors, the registered office of the Company in the State of Delaware shall be located at 1209 Orange Street, Wilmington, Delaware 19801, and the registered agent for service of process on the Company in the State of Delaware at such registered office shall be The Corporation Trust Company. The principal office of the Company shall be located at 7700 San Felipe Suite 485, Houston, Texas 77063 or such other place as the Board of Directors may from time to time designate by notice to the Members. The Company may maintain offices at such other place or places within or outside the State of Delaware as the Board of Directors determines to be necessary or appropriate.

Section 2.4 Purposes and Business. The purpose and nature of the business to be conducted by the Company shall be to (a) serve as a member, partner or stockholder, as the case may be, of, and hold limited liability company interests, partnership (whether general or limited) interests or stock, as the case may be, in the Operating Company and, in connection therewith, to exercise all the rights and powers conferred upon the Company as a member, partner or stockholder, as the case may be, of such entities, (b) engage directly in, or enter into or form any corporation, partnership, joint venture, limited liability company or other arrangement to engage indirectly in, any business activity that the Operating Company is permitted to engage in or that its Subsidiaries are permitted to engage in by their organizational documents or agreements, as may be amended and restated from time to time, and, in connection therewith, to exercise all of the rights and powers conferred upon the Company pursuant to the agreements, as may be amended from time to time, relating to such business activity, (c) engage directly in, or enter into or form any corporation, partnership, joint venture, limited liability company or other arrangement to engage indirectly in, any business activity that is approved by the Board of Directors and that lawfully may be conducted by a limited liability company organized pursuant to the Delaware Act and, in connection therewith, to exercise all of the rights and powers conferred upon the Company pursuant to the agreements relating to such business activity; and (d) do anything necessary or appropriate to the foregoing, including the making of capital contributions or loans to a Group Member; provided, however, that the Company shall not engage, directly or indirectly, in any business activity that the Board of Directors determines would cause the Company to be treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes. The Board of Directors has no obligation or duty to the Company or the Members to propose or approve, and may decline to propose or approve, the conduct by the Company of any business.

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Section 2.5 Powers. The Company shall be empowered to do any and all acts and things necessary and appropriate for the furtherance and accomplishment of the purposes and business described in Section 2.4 and for the protection and benefit of the Company.

Section 2.6 Power of Attorney. Each Member and Assignee hereby constitutes and appoints each of the Chief Executive Officer, the President and the Secretary and, if a Liquidator shall have been selected pursuant to Section 10.2, the Liquidator (and any successor to the Liquidator by merger, transfer, assignment, election or otherwise) and each of their authorized officers and attorneys-in-fact, as the case may be, with full power of substitution, as his true and lawful agent and attorney-in-fact, with full power and authority in his name, place and stead, to:

(a) execute, swear to, acknowledge, deliver, file and record in the appropriate public offices:

(i) all certificates, documents and other instruments (including this Agreement and the Certificate of Formation and all amendments or restatements hereof or thereof) that the Chief Executive Officer, President or Secretary, or the Liquidator, determines to be necessary or appropriate to form, qualify or continue the existence or qualification of the Company as a limited liability company in the State of Delaware and in all other jurisdictions in which the Company may conduct business or own property;

(ii) all certificates, documents and other instruments that the Chief Executive Officer, President or Secretary, or the Liquidator, determines to be necessary or appropriate to reflect, in accordance with its terms, any amendment, change, modification or restatement of this Agreement;

(iii) all certificates, documents and other instruments (including conveyances and a certificate of cancellation) that the Board of Directors or the Liquidator determines to be necessary or appropriate to reflect the dissolution, liquidation and termination of the Company pursuant to the terms of this Agreement;

(iv) all certificates, documents and other instruments relating to the admission, withdrawal, removal or substitution of any Member pursuant to, or other events described in, Articles IV or X;

(v) all certificates, documents and other instruments relating to the determination of the rights, preferences and privileges of any class or series of Company Securities issued pursuant to Section 5.4; and

(vi) all certificates, documents and other instruments (including agreements and a certificate of merger) relating to a merger, consolidation or conversion of the Company pursuant to Article XII.

(b) execute, swear to, acknowledge, deliver, file and record all ballots, consents, approvals, waivers, certificates, documents and other instruments that the Board of Directors or the Liquidator determines to be necessary or appropriate to (i) make, evidence, give, confirm or ratify any vote, consent, approval, agreement or other action that is made or given by the Members hereunder or is consistent with the terms of this Agreement or (ii) effectuate the terms or intent of this Agreement; provided, that when required by Section 11.2 or any other provision of this Agreement that establishes a percentage of the Members or of the Members of any class or series required to take any action, the Chief Executive Officer, President or Secretary, or the Liquidator, may exercise the power of attorney made in this Section 2.6(b) only after the necessary vote, consent or approval of the Members or of the Members of such class or series, as applicable.

Nothing contained in this Section 2.6 shall be construed as authorizing the Chief Executive Officer, President or Secretary, or the Liquidator, to amend this Agreement except in accordance with Article XI or as may be otherwise expressly provided for in this Agreement.

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(c) The foregoing power of attorney is hereby declared to be irrevocable and a power coupled with an interest, and it shall survive and, to the maximum extent permitted by law, not be affected by the subsequent death, incompetency, disability, incapacity, dissolution, bankruptcy or termination of any Member or Assignee and the transfer of all or any portion of such Member’s or Assignee’s Member Interest and shall extend to such Member’s or Assignee’s heirs, successors, assigns and personal representatives. Each such Member or Assignee hereby agrees to be bound by any representation made by the Chief Executive Officer, President or Secretary, or the Liquidator, acting in good faith pursuant to such power of attorney; and each such Member or Assignee, to the maximum extent permitted by law, hereby waives any and all defenses that may be available to contest, negate or disaffirm the action of the Chief Executive Officer, President or Secretary, or the Liquidator, taken in good faith under such power of attorney. Each Member or Assignee shall execute and deliver to the Chief Executive Officer, President or Secretary, or the Liquidator, within 15 days after receipt of the request therefor, such further designation, powers of attorney and other instruments as any of such Officers or the Liquidator, determines to be necessary or appropriate to effectuate this Agreement and the purposes of the Company.

Section 2.7 Term. The Company’s term shall be perpetual, unless and until it is dissolved in accordance with the provisions of Article X. The existence of the Company as a separate legal entity shall continue until the cancellation of the Certificate of Formation as provided in the Delaware Act.

Section 2.8 Title to Company Assets. Title to Company assets, whether real, personal or mixed and whether tangible or intangible, shall be deemed to be owned by the Company as an entity, and no Member, Director or Officer, individually or collectively, shall have any ownership interest in such Company assets or any portion thereof. Title to any or all of the Company assets may be held in the name of the Company or one or more nominees, as the Board of Directors may determine. The Company hereby declares and warrants that any Company assets for which record title is held in the name of one or more of its Affiliates or one or more nominees shall be held by such Affiliates or nominees for the use and benefit of the Company in accordance with the provisions of this Agreement; provided, however, that the Board of Directors shall use reasonable efforts to cause record title to such assets (other than those assets in respect of which the Board of Directors determines that the expense and difficulty of conveyancing makes transfer of record title to the Company impracticable) to be vested in the Company as soon as reasonably practicable. All Company assets shall be recorded as the property of the Company in its books and records, irrespective of the name in which record title to such Company assets is held.

ARTICLE III

RIGHTS OF MEMBERS

Section 3.1 Members.

(a) A Person shall be admitted as a Member and shall become bound by the terms of this Agreement if such Person purchases or otherwise lawfully acquires any Member Interest and becomes the Record Holder of such Member Interest in accordance with the provisions of Article IV hereof. Except as otherwise provided in Article IV, a Person may become a Record Holder without the consent or approval of any of the Members. Notwithstanding the foregoing, a Person may not become a Member without acquiring a Member Interest. The rights and obligations of a Person who is a Non-citizen Assignee shall be determined in accordance with Section 4.7 hereof.

(b) The name and mailing address of each Member shall be listed on the books and records of the Company maintained for such purpose by the Company or the Transfer Agent. The Secretary of the Company shall update the books and records of the Company from time to time as necessary to reflect accurately the information therein (or shall cause the Transfer Agent to do so, as applicable). A Member’s Member Interest may be represented by a Certificate, as provided in Section 4.1 hereof.

(c) As provided in Section 18-303 of the Delaware Act, the debts, obligations and liabilities of the Company, whether arising in contract, tort or otherwise, shall be solely the debts, obligations and

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liabilities of the Company. The Members shall have no liability under this Agreement, or for any such debt, obligation or liability of the Company, in their capacity as a Member, except as expressly required in this Agreement or the Delaware Act.

(d) Members may not be expelled from or removed as Members of the Company, other than in accordance with Section 4.7 or Section 4.8. Members shall not have any right to withdraw from the Company; provided, that when a transferee of a Member’s Member Interest becomes a Record Holder of such Member Interest, such transferring Member shall cease to be a Member with respect to the Member Interest so transferred.

Section 3.2 Management of Business. No Member, in its capacity as such, shall participate in the operation or management of the Company’s business, transact any business in the Company’s name or have the power to sign documents for or otherwise bind the Company by reason of being a Member.

Section 3.3 Outside Activities of the Members. Any Member shall be entitled to and may have business interests and engage in business activities in addition to those relating to the Company, including business interests and activities in direct competition with the Company Group. Neither the Company nor any of the other Members shall have any rights by virtue of this Agreement in any business ventures of any Member.

Section 3.4 Rights of Members.

(a) In addition to other rights provided by this Agreement or by applicable law, and except as limited by Section 3.4(b), each Member shall have the right, for a lawful purpose reasonably related to such Member’s Member Interest as a Member in the Company, upon reasonable written demand containing a concise statement of such purposes and at such Member’s own expense:

(i) to obtain true and full information regarding the status of the business and financial condition of the Company;

(ii) promptly after becoming available, to obtain a copy of the Company’s federal, state and local income tax returns for each year;

(iii) to have furnished to him a current list of the name and last known business, residence or mailing address of each Member;

(iv) to have furnished to him a copy of this Agreement and the Certificate of Formation and all amendments thereto, together with copies of the executed copies of all powers of attorney pursuant to which this Agreement, the Certificate of Formation and all amendments thereto have been executed;

(v) to obtain true and full information regarding the amount of cash and a description and statement of the Net Agreed Value of any other Capital Contribution by each Member and that each Member has agreed to contribute in the future, and the date on which each became a Member; and

(vi) to obtain such other information regarding the affairs of the Company as is just and reasonable and consistent with the stated purposes of the written demand.

(b) The Board of Directors may keep confidential from the Members, for such period of time as the Board of Directors determines, (i) any information that the Board of Directors determines to be in the nature of trade secrets or (ii) other information the disclosure of which the Board of Directors determines (A) is not in the best interests of the Company Group, (B) could damage the Company Group or (C) that any Group Member is required by law, by the rules of any National Securities Exchange on which any Company Security is listed for trading, or by agreement with any third party to keep confidential (other than agreements with Affiliates of the Company the primary purpose of which is to circumvent the obligations set forth in this Section 3.4).

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ARTICLE IV

CERTIFICATES; RECORD HOLDERS;
TRANSFER OF INTERESTS; REDEMPTION OF INTERESTS

Section 4.1 Certificates. Upon the Company’s issuance of Units to any Person, the Company may issue one or more Certificates in the name of such Person evidencing the number of such Units being so issued. In addition, upon the request of any Person owning any other Company Securities other than Units, the Company shall issue to such Person one or more Certificates evidencing such other Company Securities. Certificates shall be executed on behalf of the Company by the Chairman of the Board, President or any Vice President and the Secretary or any Assistant Secretary. No Unit Certificate shall be valid for any purpose until it has been countersigned by the Transfer Agent; provided, however, that if the Board of Directors elects to issue Units in global form, the Unit Certificates shall be valid upon receipt of a certificate from the Transfer Agent certifying that the Units have been duly registered in accordance with the directions of the Company. Any or all of the signatures required on the Certificate may be by facsimile. If any Officer or Transfer Agent who shall have signed or whose facsimile signature shall have been placed upon any such Certificate shall have ceased to be such Officer or Transfer Agent before such Certificate is issued by the Company, such Certificate may nevertheless be issued by the Company with the same effect as if such Person were such Officer or Transfer Agent at the date of issue. Certificates shall be consecutively numbered and shall be entered on the books and records of the Transfer Agent as they are issued and shall exhibit the holder’s name and number of Units. Subject to the requirements of Section 5.9(b), the Members holding Certificates evidencing Class B Units may exchange such Certificates for Certificates evidencing Common Units on or after the date on which such Class B Units are converted into Common Units pursuant to the terms of Section 5.11. Notwithstanding the foregoing, Units may be uncertificated.

Section 4.2 Mutilated, Destroyed, Lost or Stolen Certificates. If any mutilated Certificate is surrendered to the Transfer Agent, the appropriate Officers on behalf of the Company shall execute, and the Transfer Agent shall countersign and deliver in exchange therefor, a new Certificate evidencing the same number and type of Company Securities as the Certificate so surrendered.

(a) The appropriate Officers on behalf of the Company shall execute and deliver, and the Transfer Agent shall countersign a new Certificate in place of any Certificate previously issued if the Record Holder of the Certificate:

(i) makes proof by affidavit, in form and substance satisfactory to the Company, that a previously issued Certificate has been lost, destroyed or stolen;

(ii) requests the issuance of a new Certificate before the Company has notice that the Certificate has been acquired by a purchaser for value in good faith and without notice of an adverse claim;

(iii) if requested by the Company, delivers to the Company a bond, in form and substance satisfactory to the Company, with surety or sureties and with fixed or open penalty as the Company may direct to indemnify the Company and the Transfer Agent against any claim that may be made on account of the alleged loss, destruction or theft of the Certificate; and

(iv) satisfies any other reasonable requirements imposed by the Company.

If a Member fails to notify the Company within a reasonable time after he has notice of the loss, destruction or theft of a Certificate, and a transfer of the Member’s Member Interests represented by the Certificate is registered before the Company or the Transfer Agent receives such notification, the Member shall be precluded from making any claim against the Company or the Transfer Agent for such transfer or for a new Certificate.

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(b) As a condition to the issuance of any new Certificate under this Section 4.2, the Company may require the payment of a sum sufficient to cover any tax or other governmental charge that may be imposed in relation thereto and any other expenses (including the fees and expenses of the Transfer Agent) reasonably connected therewith.

Section 4.3 Record Holders. The Company shall be entitled to recognize the Record Holder as the owner of a Member Interest and, accordingly, shall not be bound to recognize any equitable or other claim to or interest in such Member Interest on the part of any other Person, regardless of whether the Company shall have actual or other notice thereof, except as otherwise provided by law or any applicable rule, regulation, guideline or requirement of any National Securities Exchange on which such Member Interests are listed for trading. Without limiting the foregoing, when a Person (such as a broker, dealer, bank, trust company or clearing corporation or an agent of any of the foregoing) is acting as nominee, agent or in some other representative capacity for another Person in acquiring and/or holding Member Interests, as between the Company on the one hand, and such other Persons on the other, such representative Person shall be the Record Holder of such Member Interest.

Section 4.4 Transfer Generally. The term “transfer,” when used in this Agreement with respect to a Member Interest, shall be deemed to refer to a transaction by which the holder of a Member Interest assigns such Member Interest to another Person who is or becomes a Member, and includes a sale, assignment, gift, exchange or any other disposition by law or otherwise, including any transfer upon foreclosure of any pledge, encumbrance, hypothecation or mortgage. No Member Interest shall be transferred, in whole or in part, except in accordance with the terms and conditions set forth in this Article IV. Any transfer or purported transfer of a Member Interest not made in accordance with this Article IV shall, to the fullest extent permitted by law, be null and void.

Section 4.5 Registration and Transfer of Member Interests.

(a) The Company shall keep or cause to be kept on behalf of the Company a register that, subject to such reasonable regulations as it may prescribe and subject to the provisions of Section 4.5(b), will provide for the registration and transfer of Member Interests. The Transfer Agent is hereby appointed registrar and transfer agent for the purpose of registering Units and transfers of such Units as herein provided. The Company shall not recognize transfers of Certificates evidencing Member Interests unless such transfers are effected in the manner described in this Section 4.5. Upon surrender of a Certificate for registration of transfer of any Member Interests evidenced by a Certificate, and subject to the provisions of Section 4.5(b), the appropriate Officers of the Company shall execute and deliver, and in the case of Units, the Transfer Agent shall countersign and deliver, in the name of the holder or the designated transferee or transferees, as required pursuant to the Record Holder’s instructions, one or more new Certificates, or evidence of the issuance of uncertificated Units, evidencing the same aggregate number and type of Member Interests as were evidenced by the Certificate so surrendered.

(b) Except as provided in Section 4.7, the Company shall not recognize any transfer of Member Interests until (i) the Certificates, or other evidence of the uncertificated Units, evidencing such Member Interests are surrendered for registration of transfer and (ii) following a Company Notice, such Certificates are accompanied by a Eligible Holder Certification, properly completed and duly executed by the transferee (or the transferee’s attorney-in-fact duly authorized in writing).

(c) No charge shall be imposed by the Company for such transfer; provided, that as a condition to the issuance of any new Certificate, or uncertificated issuance of Units, under this Section 4.5(b), the Company may require the payment of a sum sufficient to cover any tax or other governmental charge that may be imposed with respect thereto.

(d) By acceptance of the transfer of any Member Interest in accordance with this Section 4.5 and except as provided in Section 4.7, each transferee of a Member Interest (including any nominee holder or

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an agent or representative acquiring such Member Interests for the account of another Person) (i) shall be admitted to the Company as a Substituted Member with respect to the Member Interests so transferred to such Person when any such transfer or admission is reflected in the books and records of the Company, with or without execution of this Agreement, (ii) shall be deemed to agree to be bound by the terms of, and shall be deemed to have executed, this Agreement, (iii) shall become the Record Holder of the Member Interests so transferred, (iv) represents that the transferee has the capacity, power and authority to enter into this Agreement, (v) grants powers of attorney to the Officers of the Company and any Liquidator of the Company in accordance with Section 2.6 and (vi) makes the consents and waivers contained in this Agreement. The transfer of any Member Interests and the admission of any new Member shall not constitute an amendment to this Agreement.

(e) Prior to the conversion of Class B Units into Common Units pursuant to the terms of Section 5.11, Members owning Class B Units may only transfer such Class B Units upon the death of such Members to one or more Persons in accordance with state intestacy laws or as otherwise approved by the Board of Directors.

(f) Subject to (i) the foregoing provisions of this Section 4.5, (ii) Section 4.3, (iii) Section 4.6, (iv) with respect to any class or series of Member Interests, the provisions of any statement of designations establishing such class or series, (v) any contractual provision binding on any Member and (vi) provisions of applicable law including the Securities Act, Member Interests shall be freely transferable to any Person.

Section 4.6 Restrictions on Transfers.

(a) In addition to the restrictions set forth in Section 4.5(b) and except as provided in Section 4.6(b) below, but notwithstanding the other provisions of this Article IV, no transfer of any Member Interests shall be made if such transfer would violate the then applicable federal or state securities laws or rules and regulations of the Securities and Exchange Commission, any state securities commission or any other governmental authority with jurisdiction over such transfer.

(b) The Company may impose restrictions on the transfer of Member Interests if it receives an Opinion of Counsel providing that such restrictions are necessary to avoid a significant risk of any Group Member becoming taxable as a corporation or otherwise becoming taxable as an entity for federal income tax purposes. The Board of Directors may impose such restrictions by amending this Agreement in accordance with Article XI; provided, however, that any amendment that would result in the delisting or suspension of trading of any class of Member Interests on the principal National Securities Exchange on which such class of Member Interests is then traded must be approved, prior to such amendment being effected, by the holders of at least a majority of the Outstanding Member Interests of such class. The transfer of a Class B Unit that has converted into a Common Unit shall be subject to the restrictions imposed by Section 5.9(b).

(c) Nothing contained in this Article IV, or elsewhere in this Agreement, shall preclude the settlement of any transactions involving Member Interests entered into through the facilities of any National Securities Exchange on which such Member Interests are listed for trading.

(d) In the event any Member Interest is evidenced in certificated form, each certificate evidencing Member Interests shall bear a conspicuous legend in substantially the following form:

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(B) TERMINATE THE EXISTENCE OR QUALIFICATION OF VANGUARD NATURAL RESOURCES, LLC UNDER THE LAWS OF THE STATE OF DELAWARE, (C) CAUSE VANGUARD NATURAL RESOURCES, LLC TO BE TREATED AS AN ASSOCIATION TAXABLE AS A CORPORATION OR OTHERWISE TO BE TAXED AS AN ENTITY FOR FEDERAL INCOME TAX PURPOSES (TO THE EXTENT NOT ALREADY SO TREATED OR TAXED) OR (D) VIOLATE THE TERMS AND CONDITIONS OF THE SECOND AMENDED AND RESTATED LIMITED LIABILITY COMPANY AGREEMENT OF VANGUARD NATURAL RESOURCES, LLC, DATED [SEPTEMBER [•]], 2007, AS THE SAME MAY BE AMENDED FROM TIME TO TIME. VANGUARD NATURAL RESOURCES, LLC MAY IMPOSE ADDITIONAL RESTRICTIONS ON THE TRANSFER OF THIS SECURITY IF IT RECEIVES AN OPINION OF COUNSEL THAT SUCH RESTRICTIONS ARE NECESSARY TO AVOID A SIGNIFICANT RISK OF VANGUARD NATURAL RESOURCES, LLC BECOMING TAXABLE AS A CORPORATION OR OTHERWISE BECOMING TAXABLE AS AN ENTITY FOR FEDERAL INCOME TAX PURPOSES. THE RESTRICTIONS SET FORTH ABOVE SHALL NOT PRECLUDE THE SETTLEMENT OF ANY TRANSACTIONS INVOLVING THIS SECURITY ENTERED INTO THROUGH THE FACILITIES OF ANY NATIONAL SECURITIES EXCHANGE ON WHICH THIS SECURITY IS LISTED OR ADMITTED TO TRADING.

Section 4.7 Citizenship Certificates; Non-citizen Assignees.

(a) If any Group Member is or becomes subject to any federal, state or local law or regulation that the Board of Directors determines would create a substantial risk of cancellation or forfeiture of any property in which the Group Member has an interest based on the nationality, citizenship or other related status of a Member or Assignee, the Board of Directors may request any Member or Assignee to furnish to the Board of Directors, within 30 days after receipt of such request, an executed Citizenship Certification or such other information concerning his nationality, citizenship or other related status (or, if the Member or Assignee is a nominee holding for the account of another Person, the nationality, citizenship or other related status of such Person) as the Board of Directors may request. If a Member or Assignee fails to furnish to the Board of Directors, within the aforementioned 30-day period, such Citizenship Certification or other requested information or if upon receipt of such Citizenship Certification or other requested information the Board of Directors determines that a Member or Assignee is not an Eligible Citizen, the Member Interests owned by such Member or Assignee shall be subject to redemption in accordance with the provisions of Section 4.8. In addition, the Board of Directors may require that the status of any such Member or Assignee be changed to that of a Non-citizen Assignee and, thereupon such Member shall cease to be a member of the Company and shall have no voting rights, whether arising hereunder, under the Delaware Act, at law, in equity or otherwise, in respect of its Member Interests. The voting rights in respect of Member Interests of Non-citizen Assignees shall be deemed to have been exercised with the votes being distributed in the same ratios or for the same candidates for election as Directors as the votes of Members in respect of Member Interests other than those of Non-citizen Assignees are cast, either for, against or abstaining as to the matter or election.

(b) Upon dissolution of the Company, a Non-citizen Assignee shall have no right to receive a distribution in kind pursuant to Section 10.3, but shall be entitled to the cash equivalent thereof, and the Company shall provide cash in exchange for an assignment of the Non-citizen Assignee’s share of any distribution in kind. Such payment and assignment shall be treated for Company purposes as a purchase by the Company from the Non-citizen Assignee of his economic interest in the Company (representing his right to receive his share of such distribution in kind).

(c) At any time after he can and does certify that he has become an Eligible Citizen, a Non-citizen Assignee may, upon application to the Board of Directors, request admission as a Substituted Member, with respect to any Member Interests of such Non-citizen Assignee not redeemed pursuant to

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Section 4.8, such Non-citizen Assignee be admitted as a Member, and upon approval of the Board of Directors, such Non-citizen Assignee shall be admitted as a Member and shall no longer constitute a Non-citizen Assignee and shall reacquire all voting rights of his Member Interests.

Section 4.8 Redemption of Member Interests of Non-citizen Assignees.

(a) If at any time a Member or Assignee fails to furnish a Citizenship Certification or other information requested within the 30-day period specified in Section 4.7(a), or, if upon receipt of such Citizenship Certification or other information the Board of Directors determines, with the advice of counsel, that a Member or Assignee is not an Eligible Citizen, the Company may, unless the Member or Assignee establishes to the satisfaction of the Board of Directors that such Member or Assignee is an Eligible Citizen or has transferred his Member Interests to a Person who is an Eligible Citizen and who furnishes a Citizenship Certification to the Board of Directors prior to the date fixed for redemption as provided below, redeem the Member Interest of such Member or Assignee as follows:

(i) The Board of Directors shall, not later than the 30th day before the date fixed for redemption, give notice of redemption to the Member or Assignee, at his last address designated on the records of the Company or the Transfer Agent, by registered or certified mail, postage prepaid. The notice shall be deemed to have been given when so mailed. The notice shall specify the Redeemable Interests, the date fixed for redemption, the place of payment, that payment of the redemption price will be made upon surrender of the Certificate, or other evidence of the uncertificated Units, evidencing the Redeemable Interests and that on and after the date fixed for redemption no further allocations or distributions to which the Member would otherwise be entitled in respect of the Redeemable Interests will accrue or be made.

(ii) The aggregate redemption price for Redeemable Interests shall be an amount equal to the Current Market Price (the date of determination of which shall be the date fixed for redemption) of Member Interests of the class to be so redeemed multiplied by the number of Member Interests of each such class included among the Redeemable Interests. The redemption price shall be paid, as determined by the Board of Directors, in cash or by delivery of a promissory note of the Company in the principal amount of the redemption price, bearing interest at the Prime Rate annually and payable in three equal annual installments of principal together with accrued interest, commencing one year after the redemption date.

(iii) Upon surrender by or on behalf of the Member or Assignee, at the place specified in the notice of redemption, of the Certificate, or other evidence of the uncertificated Units, evidencing the Redeemable Interests, duly endorsed in blank or accompanied by an assignment duly executed in blank, the Member or Assignee or his duly authorized representative shall be entitled to receive the payment therefor.

(iv) After the redemption date, Redeemable Interests shall no longer constitute issued and Outstanding Member Interests.

(b) The provisions of this Section 4.8 shall also be applicable to Member Interests held by a Member or Assignee as nominee of a Person determined to be other than an Eligible Citizen.

(c) Nothing in this Section 4.8 shall prevent the recipient of a notice of redemption from transferring his Member Interest before the redemption date if such transfer is otherwise permitted under this Agreement. Upon receipt of notice of such a transfer, the Board of Directors shall withdraw the notice of redemption, provided the transferee of such Member Interest certifies to the satisfaction of the Board of Directors in a Citizenship Certification that he is an Eligible Citizen. If the transferee fails to make such certification, such redemption shall be effected from the transferee on the original redemption date.

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ARTICLE V

CAPITAL CONTRIBUTIONS AND ISSUANCE OF INTERESTS

Section 5.1 Contributions by the Members; Issuance of Interests.

(a) Nami. In connection with the formation of the Company, the Organizational Member made an initial Capital Contribution in the amount of $1,000 for all of the Member Interests then outstanding. On April 18, 2007, (i) the 36.044% Member Interest in the Operating Company held by Nami Capital was contributed to the Company in exchange for 1,171,430 Common Units, (ii) the 34.062% Member Interest in the Operating Company held by the Majeed S. Nami Irrevocable Trust dated 11. January 2007 was contributed to the Company in exchange for 1,107,015 Common Units and (iii) the 29.894% Member Interest in the Operating Company held by the Majeed S. Nami Personal Endowment Fund was contributed to the Company in exchange for 971,555 Common Units. In addition, Nami retained the right to receive a cash payment of $37.2 million from the Company, which shall reimburse Nami for certain capital expenditures made by Nami.

(b) Management. On the April 18, 2007, Scott W. Smith and Richard A. Robert were issued 240,000 and 100,000, respectively, Class B Units. On August 15, 2007, Britt Pence and Patty Avila-Eady were issued 75,000 and 5,000, respectively, Class B Units. The Company has reserved up to an additional 40,000 Class B Units to officers, directors, employees or consultants of the Company or any of its Affiliates. In addition, pursuant to the terms of their employment agreements, each of Richard A. Robert and Britt Pence will receive options to purchase 100,000 Common Units at the Initial Public Offering price.

(c) Private Investors. On April 18, 2007 and pursuant to the Purchase Agreement, each Private Investor contributed to the Company cash in an amount equal to an amount set forth opposite its name on Schedule I to the Purchase Agreement in exchange for the number of Common Units set forth opposite its name on Schedule I to the Purchase Agreement. The cash received by the Company pursuant to the immediately preceding sentence was used to retire the Company’s obligation to make a $37.2 million cash payment to Nami in reimbursement for certain capital expenditures.

(d) Underwriters. On the Closing Date and pursuant to the Underwriting Agreement, each Underwriter shall contribute to the Company cash in an amount equal to the Issue Price per Initial Common Unit, multiplied by the number of Common Units specified in the Underwriting Agreement to be purchased by such Underwriter at the Closing Date. In exchange for such Capital Contributions by the Underwriters, the Company shall issue Common Units to each Underwriter on whose behalf such Capital Contribution is made a number of Common Units equal to the number of Common Units specified in the Underwriting Agreement to be purchased by such Underwriter on the Closing Date, and upon such issuance such Underwriter shall be admitted to the Company as a Member in respect of the Common Units so issued to such Underwriter.

(e) Over-Allotment Option. Upon the exercise of the Over-Allotment Option and pursuant to the Underwriting Agreement, each Underwriter shall contribute to the Company cash in an amount equal to the Issue Price per Initial Common Unit, multiplied by the number of Common Units specified in the Underwriting Agreement to be purchased by such Underwriter at the Option Closing Date. In exchange for such Capital Contributions by the Underwriters, the Company shall issue Common Units to each Underwriter on whose behalf such Capital Contribution is made, a number of Common Units specified in the Underwriting Agreement to be purchased by such Underwriter on the Option Closing Date, and upon such issuance such Underwriter shall be admitted to the Company as a Member in respect of the Common Units so issued to such Underwriter pursuant to this Section 5.2(e). Upon receipt by the Company of the Capital Contributions from the Underwriters as provided in this Section 5.2(e), the Company shall use such cash to pay outstanding borrowings under its Credit Facility.

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Section 5.2 Interest and Withdrawal. No interest shall be paid by the Company on Capital Contributions. No Member shall be entitled to the withdrawal or return of its Capital Contribution, except to the extent, if any, that distributions made pursuant to this Agreement or upon termination of the Company may be considered as such by law and then only to the extent provided for in this Agreement. Except to the extent expressly provided in this Agreement, no Member shall have priority over any other Member either as to the return of Capital Contributions or as to profits, losses or distributions.

Section 5.3 Capital Accounts.

(a) The Company shall maintain for each Member (or a beneficial owner of Member Interests held by a nominee in any case in which the nominee has furnished the identity of such owner to the Company in accordance with Section 6031(c) of the Code or any other method acceptable to the Company) owning a Member Interest a separate Capital Account with respect to such Member Interest in accordance with the rules of Treasury Regulation Section 1.704-1(b)(2)(iv). Such Capital Account shall be increased by (i) the amount of all Capital Contributions with respect to such Member Interest and (ii) all items of Company income and gain (including Simulated Gain and income and gain exempt from tax) computed in accordance with Section 5.3(b) and allocated with respect to such Member Interest pursuant to Section 6.1, and decreased by (x) the amount of cash or Net Agreed Value of all actual and deemed distributions of cash or property made with respect to such Member Interest pursuant to this Agreement and (y) all items of Company deduction and loss (including Simulated Depletion and Simulated Loss) computed in accordance with Section 5.3(b) and allocated with respect to such Member Interest pursuant to Section 6.1.

(b) For purposes of computing the amount of any item of income, gain, loss or deduction, Simulated Depletion, Simulated Gain or Simulated Loss which is to be allocated pursuant to Article VI and is to be reflected in the Members’ Capital Accounts, the determination, recognition and classification of any such item shall be the same as its determination, recognition and classification for federal income tax purposes (including any method of depreciation, cost recovery or amortization used for that purpose); provided, that:

(i) Solely for purposes of this Section 5.3, the Company shall be treated as owning directly its proportionate share (as determined by the Board of Directors based upon the provisions of the applicable Group Member Agreement) of all property owned by any other Group Member that is classified as a partnership for federal income tax purposes.

(ii) All fees and other expenses incurred by the Company to promote the sale of (or to sell) a Member Interest that can neither be deducted nor amortized under Section 709 of the Code, if any, shall, for purposes of Capital Account maintenance, be treated as an item of deduction at the time such fees and other expenses are incurred and shall be allocated among the Members pursuant to Section 6.1.

(iii) Except as otherwise provided in Treasury Regulation Section 1.704-1(b)(2)(iv)(m), the computation of all items of income, gain, loss, deduction, Simulated Depletion, Simulated Gain and Simulated Loss shall be made without regard to any election under Section 754 of the Code, which may be made by the Company and, as to those items described in Section 705(a)(1)(B) or 705(a)(2)(B) of the Code, without regard to the fact that such items are not includable in gross income or are neither currently deductible nor capitalized for federal income tax purposes. To the extent an adjustment to the adjusted tax basis of any Company asset pursuant to Section 734(b) or 743(b) of the Code is required, pursuant to Treasury Regulation Section 1.704-1(b)(2)(iv)(m), to be taken into account in determining Capital Accounts, the amount of such adjustment in the Capital Accounts shall be treated as an item of gain or loss.

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(iv) Any income, gain, loss, Simulated Gain or Simulated Loss attributable to the taxable disposition of any Company property shall be determined as if the adjusted basis of such property as of such date of disposition were equal in amount to the Company’s Carrying Value with respect to such property as of such date.

(v) In accordance with the requirements of Section 704(b) of the Code, any deductions for depreciation, cost recovery amortization or Simulated Depletion attributable to any Contributed Property shall be determined as if the adjusted basis of such property on the date it was acquired by the Company were equal to the Agreed Value of such property. Upon an adjustment pursuant to Section 5.3(d) to the Carrying Value of any Company property subject to depreciation, cost recovery or amortization, any further deductions for such depreciation, cost recovery, amortization or Simulated Depletion attributable to such property shall be determined (A) as if the adjusted basis of such property were equal to the Carrying Value of such property immediately following such adjustment and (B) using a rate of depreciation, cost recovery, amortization or Simulated Depletion derived from the same method and useful life (or, if applicable, the remaining useful life) as is applied for federal income tax purposes; provided, however, that, if the asset has a zero adjusted basis for federal income tax purposes, depreciation, cost recovery or amortization deductions shall be determined using any method that the Board of Directors may adopt.

(c) A transferee of a Member Interest shall succeed to a Pro Rata portion of the Capital Account of the transferor relating to the Member Interest so transferred.

(d) (i) In accordance with Treasury Regulation Section 1.704-1(b)(2)(iv)(f), on an issuance of additional Member Interests for cash or Contributed Property and the issuance of Member Interests as consideration for the provision of services, the Capital Account of all Members and the Carrying Value of each Company property immediately prior to such issuance shall be adjusted upward or downward to reflect any Unrealized Gain or Unrealized Loss attributable to such Company property, as if such Unrealized Gain or Unrealized Loss had been recognized on an actual sale of each such property immediately prior to such issuance and had been allocated to the Members at such time pursuant to Section 6.1 in the same manner as any item of gain, loss, Simulated Gain or Simulated Loss actually recognized during such period would have been allocated. In determining such Unrealized Gain or Unrealized Loss, the aggregate cash amount and fair market value of all Company assets (including cash or cash equivalents) immediately prior to the issuance of additional Member Interests shall be determined by the Board of Directors using such method of valuation as it may adopt; provided, however, that the Board of Directors, in arriving at such valuation, must take fully into account the fair market value of the Member Interests of all Members at such time. The Board of Directors shall allocate such aggregate value among the assets of the Company (in such manner as it determines) to arrive at a fair market value for individual properties.

(ii) In accordance with Treasury Regulation Section 1.704-1(b)(2)(iv)(f), immediately prior to any actual or deemed distribution to a Member of any Company property (other than a distribution of cash that is not in redemption or retirement of a Member Interest), the Capital Accounts of all Members and the Carrying Value of all Company property shall be adjusted upward or downward to reflect any Unrealized Gain or Unrealized Loss attributable to such Company property, as if such Unrealized Gain or Unrealized Loss had been recognized in a sale of such property immediately prior to such distribution for an amount equal to its fair market value, and had been allocated to the Members, at such time, pursuant to Section 6.1 in the same manner as any item of gain, loss, Simulated Gain or Simulated Loss actually recognized during such period would have been allocated. In determining such Unrealized Gain or Unrealized Loss the aggregate cash amount and fair market value of all Company assets (including cash or cash equivalents) immediately prior to a distribution shall (A) in the case of an actual distribution that is not made pursuant to Section 10.3 or in the case of a deemed distribution, be determined and allocated in the same manner as that provided in Section 5.3(d)(i) or (B) in the case of a liquidating distribution

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pursuant to Section 10.3, be determined and allocated by the Liquidator using such method of valuation as it may adopt.

Section 5.4 Issuances of Additional Company Securities.

(a) Subject to Section 5.5, at any time and from time to time the Company may issue additional Company Securities, and options, rights, warrants and appreciation rights relating to the Company Securities for any Company purpose to such Persons, and admit such Persons as members of the Company, for such consideration and on such terms and conditions as the Board of Directors shall determine in its sole discretion, all without the approval of the Members of any class of Company Securities then Outstanding.

(b) Each additional Company Security authorized to be issued by the Company pursuant to Section 5.4(a) may be issued in one or more classes, or one or more series of any such classes, with such relative designations, preferences, rights, powers and duties (which may be senior or prior, pari passu or junior to the preferences, rights, powers and duties of any then Outstanding class and series of Company Securities), as shall be fixed by the Board of Directors, including (i) the right to share Company profits and losses or items thereof; (ii) the right to share in Company distributions; (iii) the rights upon dissolution and liquidation of the Company; (iv) whether, and the terms and conditions upon which, the Company may redeem the Company Security, including sinking fund provisions, if any; (v) whether such Company Security is issued with the privilege of conversion or exchange and, if so, the terms and conditions of such conversion or exchange; (vi) the terms and conditions upon which each Company Security will be issued, evidenced by certificates and assigned or transferred; (vii) the method for determining the Percentage Interest as to such Company Security; and (viii) the right, if any, of the holders of each such Company Security to vote on Company matters, including matters relating to the relative rights, preferences and privileges of such Company Security. Notwithstanding anything in this Agreement to the contrary, additional Company Securities, issuable without the approval of the Members of any class of Company Securities then Outstanding, may include (i) Company Securities with preferences, rights, powers and duties (including rights to distributions, allocation, voting or in liquidation) that are senior or prior, pari passu or junior to any other class or series of Company Securities then Outstanding, or (ii) additional Company Securities of any class or series then Outstanding.

(c) The Board of Directors shall take all actions that it determines to be necessary or appropriate in connection with (i) each issuance of Company Securities and options, rights, warrants and appreciation rights relating to Company Securities pursuant to this Section 5.4, (ii) the admission of any Person(s) as an Additional Member(s) and (iii) all additional issuances of Company Securities. The Board of Directors shall determine the relative designations, preferences, rights, powers and duties of the holders of the Units or other Company Securities being so issued. The Board of Directors shall do all things necessary to comply with the Delaware Act and is authorized and directed to do all things that it determines to be necessary or appropriate in connection with any future issuance of Company Securities pursuant to the terms of this Agreement, including compliance with any statute, rule, regulation or guideline of any federal, state or other governmental agency or any National Securities Exchange on which the Common Units or other Company Securities are listed for trading.

Section 5.5 Limitations on Issuance of Additional Company Securities. The issuance of Company Securities pursuant to Section 5.4 shall be subject to the limitation that no fractional Units shall be issued by the Company.

Section 5.6 No Preemptive Rights. No Person shall have any preemptive, preferential or other similar right with respect to the issuance of any Company Security, whether unissued, held in the treasury or hereafter created.

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Section 5.7 Splits and Combinations.

(a) Subject to Section 5.5 and Section 5.7(d), the Company may make a Pro Rata distribution of Company Securities of any class or series to all Record Holders of Company Securities of such class or series or may effect a subdivision or combination of Company Securities so long as, after any such event, each Member shall have the same Percentage Interest in the Company as before such event, and any amounts calculated on a per Unit basis or stated as a number of Units (including the number of Common Units into which Class B Units are convertible) are proportionately adjusted retroactive to the date of formation of the Company.

(b) Whenever such a distribution, subdivision or combination of Company Securities is declared, the Board of Directors shall select a Record Date as of which the distribution, subdivision or combination shall be effective and shall send notice thereof at least 20 days prior to such Record Date to each Record Holder as of a date not less than 10 days prior to the date of such notice. The Board of Directors also may cause a firm of independent public accountants selected by it to calculate the number of Company Securities to be held by each Record Holder after giving effect to such distribution, subdivision or combination. The Board of Directors shall be entitled to rely on any certificate provided by such firm as conclusive evidence of the accuracy of such calculation.

(c) Promptly following any such distribution, subdivision or combination, the Company may issue Certificates to the Record Holders of Company Securities as of the applicable Record Date representing the new number of Company Securities held by such Record Holders, or the Board of Directors may adopt such other procedures that it determines to be necessary or appropriate to reflect such changes. If any such combination results in a smaller total number of Company Securities Outstanding, the Company shall require, as a condition to the delivery to a Record Holder of such new Certificate, the surrender of any Certificate held by such Record Holder immediately prior to such Record Date.

(d) The Company shall not issue fractional Units upon any distribution, subdivision or combination of Units. If a distribution, subdivision or combination of Units would result in the issuance of fractional Units but for the provisions of this Section 5.7(d), each fractional Unit shall be rounded to the nearest whole Unit (and a 0.5 Unit shall be rounded to the next higher Unit).

Section 5.8 Fully Paid and Non-Assessable Nature of Interests. All Member Interests issued pursuant to, and in accordance with the requirements of, this Article V shall be validly issued, fully paid and non-assessable Member Interests in the Company, except as such non-assessability may be affected by Sections 18-607 or 18-804 of the Delaware Act and except to the extent otherwise provided in this Agreement.

Section 5.9 Special Provisions Relating to the Holders of Class B Units.

(a) Except as otherwise provided in the Agreement, the holder of a Class B Unit shall have all of the rights and obligations of a Member holding Common Units hereunder, including voting rights that are identical to the voting rights of Common Units, and the Class B Units will vote with the Common Units as a single class, so that each Class B Unit will be entitled to one vote on each matter with respect to which each Common Unit is entitled to vote. Immediately upon the conversion of a Class B Unit into a Common Unit pursuant to Section 5.11, the holder of a Class B Unit that has converted into a Common Unit shall possess all of the rights and obligations of a Unitholder holding a Common Unit hereunder; provided, however, that a converted Class B Unit shall remain subject to the provisions of Section 5.9(b) and Section 6.1(d)(x).

(b) The holder of a Class B Unit that has converted into a Common Unit pursuant to Section 5.11 shall not be issued a Common Unit Certificate pursuant to Section 4.1 and shall not be permitted to transfer its converted Class B Units to a Person that is not an Affiliate of the holder until such

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time as the Company determines, based on advice of counsel, that a converted Class B Unit should have, as a substantive matter, like intrinsic economic and United States federal income tax characteristics, in all material respects, to the intrinsic economic and United States federal income tax characteristics of a Common Unit then Outstanding. In connection with the condition imposed by this Section 5.9(b), the Company shall take whatever steps are required to provide economic uniformity to the converted Class B Units in preparation for a transfer of such converted Class B Units, including the application of Section 6.1(d)(x); provided, however, that no such steps may be taken that would have a material adverse effect on the Unitholders holding Common Units represented by Common Unit Certificates.

Section 5.10 Registration Rights of Nami and Its Affiliates.

(a) If following the Initial Public Offering (i) Nami or any of its Affiliates holds Company Securities that it desires to sell and (ii) Rule 144 of the Securities Act (or any successor rule or regulation to Rule 144) or another exemption from registration is not available to enable such holder of Company Securities (the “Holder”) to dispose of the number of Company Securities it desires to sell at the time it desires to do so without registration under the Securities Act, then at the option and upon the request of the Holder, the Company shall file with the Commission as promptly as practicable after receiving such request, and use all commercially reasonable efforts to cause to become effective and remain effective for a period following its effective date until all Company Securities covered by such registration statement have been sold or until Rule 144 of the Securities Act (or any successor rule or regulation to Rule 144) becomes available for such Company Securities, a registration statement under the Securities Act registering the offering and sale of the number of Company Securities specified by the Holder (which registration statement may constitute a “shelf” registration statement covering the Company Securities specified by the Holder on an appropriate form under Rule 415 under the Securities Act, or any similar rule that may be adopted by the Commission); provided, however, that the Company shall not be required to effect more than three registrations pursuant to this Section 5.10(a); and provided further, however, that if the Conflicts Committee determines in good faith that the requested registration, or use of any prospectus forming a part thereof, would be materially detrimental to the Company and its Members because such registration would (x) materially interfere with a significant acquisition, reorganization or other similar transaction involving the Company, (y) require premature disclosure of material information that the Company has a bona fide business purpose for preserving as confidential or (z) render the Company unable to comply with requirements under applicable securities laws, then the Company shall have the right to postpone such requested registration or use of any such prospectus for a period of not more than three months after receipt of the Holder’s request, such right to postpone a requested registration or use of any such prospectus pursuant to this Section 5.10(a) not to be utilized more than once in any twelve-month period. Except as provided in the preceding sentence, the Company shall be deemed not to have used all commercially reasonable efforts to keep the registration statement effective during the applicable period if it voluntarily takes any action that would result in Holders of Company Securities covered thereby not being able to offer and sell such Company Securities at any time during such period, unless such action is required by applicable law. In connection with any registration pursuant to this Section 5.10(a), the Company shall (i) promptly prepare and file (A) such documents as may be necessary to register or qualify the securities subject to such registration under the securities laws of such states as the Holder shall reasonably request; provided, however, that no such qualification shall be required in any jurisdiction where, as a result thereof, the Company would become subject to general service of process or to taxation or qualification to do business as a foreign corporation, limited liability company or partnership doing business in such jurisdiction solely as a result of such registration, and (B) such documents as may be necessary to apply for listing or to list the Company Securities subject to such registration on such National Securities Exchange as the Holder shall reasonably request, and (ii) do any and all other acts and things that may be necessary or appropriate to enable the Holder to consummate a public sale of such Company Securities in such states. If the proposed offering pursuant to this Section 5.10(a) shall be an underwritten offering, then, in the event that the managing underwriter or

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managing underwriters of such offering advise the Company and the Holder in writing that in their opinion the inclusion of all or some of the Holder’s Company Securities, would adversely and materially affect the success of the offering, the Company shall include in such offering only that number or amount, if any, of securities held by the Holder that, in the opinion of the managing underwriter or managing underwriters, will not so adversely and materially affect the offering. Any reduction, pursuant to the preceding sentence, in the number of Company Securities that will be registered shall be subject to further reduction as a result of any other registration rights granted by the Company to other Persons, whether existing at this time or granted in the future. Except as set forth in Section 5.10(c), all costs and expenses of any such registration and offering (other than the underwriting discounts and commissions) shall be paid by the Company, without reimbursement by the Holder.

(b) If the Company shall at any time propose to file a registration statement under the Securities Act for an offering of equity securities of the Company for cash (other than an offering relating solely to an employee benefit plan or a business combination), the Company shall use all commercially reasonable efforts to include such number or amount of securities held by any Holder in such registration statement as the Holder shall request; provided, that the Company is not required to make any effort or take any action to so include the securities of the Holder once the registration statement becomes or is declared effective by the Commission, including any registration statement providing for the offering from time to time of securities pursuant to Rule 415 of the Securities Act. If the proposed offering pursuant to this Section 5.10(b) shall be an underwritten offering, then, in the event that the managing underwriter or managing underwriters of such offering advise the Company and the Holder in writing that in their opinion the inclusion of all or some of the Holder’s Company Securities, in addition to the equity securities of the Company that the Company proposes to sell, would adversely and materially affect the success of the offering, the Company shall include in such offering only that number or amount, if any, of securities held by the Holder that, in the opinion of the managing underwriter or managing underwriters, will not so adversely and materially affect the offering. Any reduction, pursuant to the preceding sentence, in the number of Company Securities that will be registered shall be subject to further reduction as a result of any other registration rights granted by the Company to other Persons, whether existing at this time or granted in the future. Except as set forth in Section 5.10(c), all costs and expenses of any such registration and offering (other than the underwriting discounts and commissions) shall be paid by the Company, without reimbursement by the Holder.

(c) If underwriters are engaged in connection with any registration referred to in this Section 5.10, the Company shall provide indemnification, representations, covenants, opinions and other assurance to the underwriters in form and substance reasonably satisfactory to such underwriters. Further, in addition to and not in limitation of the Company’s obligation under Section 7.7, the Company shall, to the fullest extent permitted by law, indemnify and hold harmless the Holder, its officers, directors and each Person who controls the Holder (within the meaning of the Securities Act) and any agent thereof (collectively, “Indemnified Persons”) from and against any and all losses, claims, damages, liabilities, joint or several, expenses (including legal fees and expenses), judgments, fines, penalties, interest, settlements or other amounts arising from any and all claims, demands, actions, suits or proceedings, whether civil, criminal, administrative or investigative, in which any Indemnified Person may be involved, or is threatened to be involved, as a party or otherwise, under the Securities Act or otherwise (hereinafter referred to in this Section 5.10(c) as a “claim” and in the plural as “claims”) based upon, arising out of or resulting from any untrue statement or alleged untrue statement of any material fact contained in any registration statement under which any Company Securities were registered under the Securities Act or any state securities or Blue Sky laws, in any preliminary prospectus (if used prior to the effective date of such registration statement), or in any summary or final prospectus or in any amendment or supplement thereto (if used during the period the Company is required to keep the registration statement current), or arising out of, based upon or resulting from the omission or alleged omission to state therein a material fact required to be stated therein or necessary to make the statements made therein not misleading;

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provided, however, that the Company shall not be liable to any Indemnified Person to the extent that any such claim arises out of, is based upon or results from an untrue statement or alleged untrue statement or omission or alleged omission made in such registration statement, such preliminary, summary or final prospectus or such amendment or supplement, in reliance upon and in conformity with written information furnished to the Company by or on behalf of such Indemnified Person specifically for use in the preparation thereof.

(d) The rights to cause the Company to register Company Securities pursuant to this Section 5.10 may be assigned (but only with all related obligations) by a Holder to a transferee or assignee of such Company Securities, provided (i) the Company is, within a reasonable time after such transfer, furnished with written notice of the name and address of such transferee or assignee and the Company Securities with respect to which such registration rights are being assigned; and (ii) such transferee or assignee agrees in writing to be bound by and subject to the terms set forth in this Section 5.10.

(e) Any request to register Company Securities pursuant to this Section 5.10 shall (i) specify the Company Securities intended to be offered and sold by the Person making the request, (ii) express such Person’s present intent to offer such Company Securities for distribution, (iii) describe the nature or method of the proposed offer and sale of Company Securities, and (iv) contain the undertaking of such Person to provide all such information and materials and take all action as may be required in order to permit the Company to comply with all applicable requirements in connection with the registration of such Company Securities.

Section 5.11 Conversion of the Class B Units.

(a) Upon written notice to the Company (a “Conversion Notice”), a holder of Class B Units will have the right to require the Company to convert:

(i) up to one-half of the Class B Units held by such holder on or at any time after the first anniversary of the closing of the Initial Public Offering;

(ii) all or any portion of the Class B Units held by such holder on or at any time after the second anniversary of the closing of the Initial Public Offering; and

(iii) upon the occurrence of an Acceleration Vesting Event in respect of such holder, all or any portion of the Class B Units held by such holder;

in each case into Common Units on a one-for-one basis.

(b) Upon election by any holder of Class B Units to cause the conversion of Class B Units in accordance with this Section 5.11, each converting holder shall deliver the Conversion Notice and the Certificates representing such Class B Units to the Company in proper transfer form. Upon receipt of such Conversion Notice and Certificates, the Company shall issue the Common Units issuable upon conversion. Each Class B Unit shall be cancelled by the Company upon its conversion.

(c) A Common Unit that has been converted from a Class B Unit pursuant to this Section 5.11 shall be subject to the provisions of Section 5.9(b) and Section 6.1(d)(x).

(d) The issuance or delivery of any Certificates for Common Units upon the conversion of Class B Units will be made without charge to the converting holder of Class B Units for such Certificates and such Certificates shall be issued or delivered in the respective names of, or in such names as may be directed by, the holders of the Class B Units converted; provided, however, that the Company shall not be required to pay any tax which may be payable in respect of any transfer involved in the issuance and delivery of any such Certificate in a name other than that of the holder of the Class B Units converted, and the Company shall not be required to issue or deliver such Certificates unless or until the Persons

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requesting the issuance or delivery thereof shall have paid to the Company the amount of such tax or shall have established to the reasonable satisfaction of the Partnership that such tax has been paid.

(e) The Class B Units may be subject to forfeiture to the Company upon the occurrence of any event specified in any agreement, plan or arrangement, including any employment agreement, grant agreement or an employee benefit plan, pursuant to which Class B Units were granted to such Person.

ARTICLE VI

ALLOCATIONS AND DISTRIBUTIONS

Section 6.1 Allocations for Capital Account Purposes. For purposes of maintaining the Capital Accounts and in determining the rights of the Members among themselves, the Company’s items of income, gain, loss, deduction, Simulated Depletion, Simulated Gain and Simulated Loss (computed in accordance with Section 5.3(b)) shall be allocated among the Members in each taxable year (or portion thereof) as provided herein below.

(a) Net Income. After giving effect to the special allocations set forth in Section 6.1(d), Net Income for each taxable year and all items of income, gain, loss, deduction, Simulated Depletion, Simulated Gain and Simulated Loss taken into account in computing Net Income for such taxable year shall be allocated to the Unitholders in accordance with their respective Percentage Interests.

(b) Net Losses. After giving effect to the special allocations set forth in Section 6.1(d), Net Losses for each taxable period and all items of income, gain, loss, deduction, Simulated Depletion, Simulated Gain and Simulated Loss taken into account in computing Net Losses for such taxable period shall be allocated to the Unitholders in accordance with their respective Percentage Interests; provided that Net Losses shall not be allocated pursuant to this Section 6.1(b) to the extent that such allocation would cause any Unitholder to have a deficit balance in its Adjusted Capital Account at the end of such taxable year (or increase any existing deficit balance in its Adjusted Capital Account).

(c) Net Termination Gains and Losses. After giving effect to the special allocations set forth in Section 6.1(d), all items of income, gain, loss, deduction, Simulated Depletion, Simulated Gain and Simulated Loss taken into account in computing Net Termination Gain or Net Termination Loss for such taxable period shall be allocated in the same manner as such Net Termination Gain or Net Termination Loss is allocated hereunder. All allocations under this Section 6.1(c) shall be made after Capital Account balances have been adjusted by all other allocations provided under this Section 6.1 and after all distributions of Available Cash provided under Section 6.4 have been made; provided, however, that solely for purposes of this Section 6.1(c), Capital Accounts shall not be adjusted for distributions made pursuant to Section 10.3.

(i) If a Net Termination Gain is recognized (or deemed recognized pursuant to Section 5.3(d)), such Net Termination Gain shall be allocated among the Members in the following manner (and the Capital Accounts of the Members shall be increased by the amount so allocated in each of the following subclauses, in the order listed, before an allocation is made pursuant to the next succeeding subclause):

(A) First, to each Member having a deficit balance in its Capital Account, in the proportion that such deficit balance bears to the total deficit balances in the Capital Accounts of all Members, until each such Member has been allocated Net Termination Gain equal to any such deficit balance in its Capital Account; and

(B) Second, 100% to all Unitholders in accordance with their respective Percentage Interests.

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(ii) If a Net Termination Loss is recognized (or deemed recognized pursuant to Section 5.3(d)), such Net Termination Loss shall be allocated among the Members in the following manner:

(A) First, to the Unitholders, Pro Rata, until the Capital Account in respect of each Unit then Outstanding has been reduced to zero; and

(B) Second, the balance, if any, 100% to all Unitholders in accordance with their respective Percentage Interests.

(d) Special Allocations. Notwithstanding any other provision of this Section 6.1, the following special allocations shall be made for such taxable period:

(i) Company Minimum Gain Chargeback. Notwithstanding any other provision of this Section 6.1, if there is a net decrease in Company Minimum Gain during any Company taxable period, each Member shall be allocated items of Company income, gain and Simulated Gain for such period (and, if necessary, subsequent periods) in the manner and amounts provided in Treasury Regulation Sections 1.704-2(f)(6), 1.704-2(g)(2) and 1.704-2(j)(2)(i), or any successor provision. For purposes of this Section 6.1(d), each Member’s Adjusted Capital Account balance shall be determined, and the allocation of income, gain and Simulated Gain required hereunder shall be effected, prior to the application of any other allocations pursuant to this Section 6.1(d) with respect to such taxable period (other than an allocation pursuant to Section 6.1(d)(vi) and Section 6.1(d)(vii)). This Section 6.1(d)(i) is intended to comply with the Company Minimum Gain chargeback requirement in Treasury Regulation Section 1.704-2(f) and shall be interpreted consistently therewith.

(ii) Chargeback of Member Nonrecourse Debt Minimum Gain. Notwithstanding the other provisions of this Section 6.1 (other than Section 6.1(d)(i)), except as provided in Treasury Regulation Section 1.704-2(i)(4), if there is a net decrease in Member Nonrecourse Debt Minimum Gain during any Company taxable period, any Member with a share of Member Nonrecourse Debt Minimum Gain at the beginning of such taxable period shall be allocated items of Company income, gain and Simulated Gain for such period (and, if necessary, subsequent periods) in the manner and amounts provided in Treasury Regulation Sections 1.704-2(i)(4) and 1.704-2(j)(2)(ii), or any successor provisions. For purposes of this Section 6.1(d), each Member’s Adjusted Capital Account balance shall be determined, and the allocation of income, gain and Simulated Gain required hereunder shall be effected, prior to the application of any other allocations pursuant to this Section 6.1(d), other than Section 6.1(d)(i) and other than an allocation pursuant to Section 6.1(d)(vi) and Section 6.1(d)(vii), with respect to such taxable period. This Section 6.1(d)(ii) is intended to comply with the chargeback of items of income and gain requirement in Treasury Regulation Section 1.704-2(i)(4) and shall be interpreted consistently therewith.

(iii) Priority Allocations. If the amount of distributions accrued pursuant to Section 6.3(a)(i) with respect to any Private Investor for a taxable year is greater (on a per Unit basis) than the amount of distributions accrued pursuant to Section 6.3(a)(i) with respect to other Members (on a per Unit basis), there shall be allocated items of Company gross income, gain and Simulated Gain to each Private Investor receiving such greater distribution accrual until the aggregate amount of such items allocated to such Member pursuant to this Section 6.1(d)(iii) for the current taxable year and all previous taxable years is equal to the product of (A) the amount by which the distribution accrual (on a per Unit basis) to such Member exceeds the distribution accrual (on a per Unit Basis) to such Members receiving the smaller distribution accrual and (B) the number of Units owned by the Member receiving the greater distribution accrual.

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(iv) Qualified Income Offset. In the event any Member unexpectedly receives any adjustments, allocations or distributions described in Treasury Regulation Sections 1.704-1(b)(2)(ii)(d)(4), 1.704-1(b)(2)(ii)(d)(5), or 1.704-1(b)(2)(ii)(d)(6), items of Company income, gain and Simulated Gain shall be specially allocated to such Member in an amount and manner sufficient to eliminate, to the extent required by the Treasury Regulations promulgated under Section 704(b) of the Code, the deficit balance, if any, in its Adjusted Capital Account created by such adjustments, allocations or distributions as quickly as possible unless such deficit balance is otherwise eliminated pursuant to Section 6.1(d)(i) or Section 6.1(d)(ii).

(v) Gross Income Allocations. In the event any Member has a deficit balance in its Capital Account at the end of any Company taxable period in excess of the sum of (A) the amount such Member is required to restore pursuant to the provisions of this Agreement and (B) the amount such Member is deemed obligated to restore pursuant to Treasury Regulation Sections 1.704-2(g) and 1.704-2(i)(5), such Member shall be specially allocated items of Company gross income, gain and Simulated Gain in the amount of such excess as quickly as possible; provided, that an allocation pursuant to this Section 6.1(d)(vi) shall be made only if and to the extent that such Member would have a deficit balance in its Capital Account as adjusted after all other allocations provided for in this Section 6.1 have been tentatively made as if this Section 6.1(d)(v) were not in this Agreement.

(vi) Nonrecourse Deductions. Nonrecourse Deductions for any taxable period shall be allocated to the Members in accordance with their respective Percentage Interests. If the Board of Directors determines that the Company’s Nonrecourse Deductions should be allocated in a different ratio to satisfy the safe harbor requirements of the Treasury Regulations promulgated under Section 704(b) of the Code, the Board of Directors is authorized, upon notice to the other Members, to revise the prescribed ratio to the numerically closest ratio that does satisfy such requirements.

(vii) Member Nonrecourse Deductions. Member Nonrecourse Deductions for any taxable period shall be allocated 100% to the Member that bears the Economic Risk of Loss with respect to the Member Nonrecourse Debt to which such Member Nonrecourse Deductions are attributable in accordance with Treasury Regulation Section 1.704-2(i). If more than one Member bears the Economic Risk of Loss with respect to a Member Nonrecourse Debt, such Member Nonrecourse Deductions attributable thereto shall be allocated between or among such Members in accordance with the ratios in which they share such Economic Risk of Loss.

(viii) Nonrecourse Liabilities. For purposes of Treasury Regulation Section 1.752-3(a)(3), the Members agree that Nonrecourse Liabilities of the Company in excess of the sum of (A) the amount of Company Minimum Gain and (B) the total amount of Nonrecourse Built-in Gain shall be allocated among the Members in accordance with their respective Percentage Interests.

(ix) Code Section 754 Adjustments. To the extent an adjustment to the adjusted tax basis of any Company asset pursuant to Section 734(b) or 743(b) of the Code is required, pursuant to Treasury Regulation Section 1.704-1(b)(2)(iv)(m), to be taken into account in determining Capital Accounts, the amount of such adjustment to the Capital Accounts shall be treated as an item of gain or Simulated Gain (if the adjustment increases the basis of the asset) or loss or Simulated Loss (if the adjustment decreases such basis), and such item of gain or loss shall be specially allocated to the Members in a manner consistent with the manner in which their Capital Accounts are required to be adjusted pursuant to such Section of the Treasury Regulations.

(x) Converted Class B Units; Economic Uniformity. With respect to any taxable period ending upon, or after, the date a Conversion Notice is given by a holder of Class B Units pursuant to Section 5.11, items of Company income and gain shall be allocated 100% to each Member

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holding such Class B Units until each such Member has been allocated an amount of Company income or gain that increases the Capital Account maintained with respect to such converted Class B Units to an amount equal to the product of (A) the number of converted Class B Units and (B) the Per Unit Capital Account for a Common Unit. The purpose for this allocation is to establish uniformity between the Capital Accounts underlying converted Class B Units and the Capital Accounts underlying Common Units.

(xi) Curative Allocation.

(A) Notwithstanding any other provision of this Section 6.1, other than the Required Allocations, the Required Allocations shall be taken into account in making the Agreed Allocations so that, to the extent possible, the net amount of items of income, gain, loss, deduction, Simulated Depletion, Simulated Gain or Simulated Loss allocated to each Member pursuant to the Required Allocations and the Agreed Allocations, together, shall be equal to the net amount of such items that would have been allocated to each such Member under the Agreed Allocations had the Required Allocations and the related Curative Allocation not otherwise been provided in this Section 6.1. Notwithstanding the preceding sentence, Required Allocations relating to (1) Nonrecourse Deductions shall not be taken into account except to the extent that there has been a decrease in Company Minimum Gain and (2) Member Nonrecourse Deductions shall not be taken into account except to the extent that there has been a decrease in Member Nonrecourse Debt Minimum Gain. Allocations pursuant to this Section 6.1(d)(xi)(A) shall only be made with respect to Required Allocations to the extent the Board of Directors reasonably determines that such allocations will otherwise be inconsistent with the economic agreement among the Members. Further, allocations pursuant to this Section 6.1(d)(xi)(A) shall be deferred with respect to allocations pursuant to clauses (1) and (2) hereof to the extent the Board of Directors determines that such allocations are likely to be offset by subsequent Required Allocations.

(B) The Board of Directors shall, with respect to each taxable period, (1) apply the provisions of Section 6.1(d)(xi)(A) in whatever order is most likely to minimize the economic distortions that might otherwise result from the Required Allocations, and (2) divide all allocations pursuant to Section 6.1(d)(xi)(A) among the Members in a manner that is likely to minimize such economic distortions.

Section 6.2 Allocations for Tax Purposes.

(a) Except as otherwise provided herein, for federal income tax purposes, each item of income, gain, loss and deduction shall be allocated among the Members in the same manner as its correlative item of “book” income, gain, loss or deduction is allocated pursuant to Section 6.1.

(b) The deduction for depletion with respect to each separate oil and gas property (as defined in Section 614 of the Code) shall be computed for federal income tax purposes separately by the Members rather than by the Company in accordance with Section 613A(c)(7)(D) of the Code. Except as provided in Section 6.2(c)(iii), for purposes of such computation (before taking into account any adjustments resulting from an election made by the Company under Section 754 of the Code), the adjusted tax basis of each oil and gas property (as defined in Section 614 of the Code) shall be allocated among the Members in accordance with their respective Percentage Interests.

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Each Member shall separately keep records of his share of the adjusted tax basis in each oil and gas property, allocated as provided above, adjust such share of the adjusted tax basis for any cost or percentage depletion allowable with respect to such property, and use such adjusted tax basis in the computation of its cost depletion or in the computation of his gain or loss on the disposition of such property by the Company.

(c) Except as provided in Section 6.2(c)(iii), for the purposes of the separate computation of gain or loss by each Member on the sale or disposition of each separate oil and gas property (as defined in Section 614 of the Code), the Company’s allocable share of the “amount realized” (as such term is defined in Section 1001(b) of the Code) from such sale or disposition shall be allocated for federal income tax purposes among the Members as follows:

(i) first, to the extent such amount realized constitutes a recovery of the Simulated Basis of the property, to the Members in the same proportion as the depletable basis of such property was allocated to the Members pursuant to Section 6.2(b) (without regard to any special allocation of basis under Section 6.2(c)(iii));

(ii) second, the remainder of such amount realized, if any, to the Members so that, to the maximum extent possible, the amount realized allocated to each Member under this Section 6.2(c)(ii) will equal such Member’s share of the Simulated Gain recognized by the Company from such sale or disposition.

(iii) The Members recognize that with respect to Contributed Property and Adjusted Property there will be a difference between the Carrying Value of such property at the time of contribution or revaluation, as the case may be, and the adjusted tax basis of such property at that time. All items of tax depreciation, cost recovery, amortization, adjusted tax basis of depletable properties, amount realized and gain or loss with respect to such Contributed Property and Adjusted Property shall be allocated among the Members to take into account the disparities between the Carrying Values and the adjusted tax basis with respect to such properties in accordance with the principles of Treasury Regulation Section 1.704-3(d).

(iv) Any elections or other decisions relating to such allocations shall be made by the Board of Directors in any manner that reasonably reflects the purpose and intention of the Agreement.

(d) In an attempt to eliminate Book-Tax Disparities attributable to a Contributed Property or Adjusted Property, other than an oil and gas property pursuant to Section 6.2(c), items of income, gain, loss, depreciation, amortization and cost recovery deductions shall be allocated for federal income tax purposes among the Members as follows:

(i) (A) In the case of a Contributed Property, such items attributable thereto shall be allocated among the Members in the manner provided under Section 704(c) of the Code that takes into account the variation between the Agreed Value of such property and its adjusted basis at the time of contribution; and (B) any item of Residual Gain or Residual Loss attributable to a Contributed Property shall be allocated among the Members in the same manner as its correlative item of “book” gain or loss is allocated pursuant to Section 6.1.

(ii) (A) In the case of an Adjusted Property, such items shall (1) first, be allocated among the Members in a manner consistent with the principles of Section 704(c) of the Code to take into account the Unrealized Gain or Unrealized Loss attributable to such property and the allocations thereof pursuant to Section 5.3(d)(i) or Section 5.3(d)(ii), and (2) second, in the event such property was originally a Contributed Property, be allocated among the Members in a manner consistent with Section 6.2(d)(i)(A); and (B) any item of Residual Gain or Residual Loss

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attributable to an Adjusted Property shall be allocated among the Members in the same manner as its correlative item of “book” gain or loss is allocated pursuant to Section 6.1.

(iii) The Board of Directors shall apply the principles of Treasury Regulation Section 1.704-3(d) to eliminate Book-Tax Disparities.

(e) For the proper administration of the Company and for the preservation of uniformity of the Units (or any class or classes thereof), the Board of Directors shall (i) adopt such conventions as it deems appropriate in determining the amount of depreciation, amortization and cost recovery deductions; (ii) make special allocations for federal income tax purposes of income (including gross income) or deductions; and (iii) amend the provisions of this Agreement as appropriate (x) to reflect the proposal or promulgation of Treasury Regulations under Section 704(b) or Section 704(c) of the Code or (y) otherwise to preserve or achieve uniformity of the Common Units (or any class or classes thereof). The Board of Directors may adopt such conventions, make such allocations and make such amendments to this Agreement as provided in this Section 6.2(e) only if such conventions, allocations or amendments would not have a material adverse effect on the Members, the holders of any class or classes of Common Units issued and Outstanding or the Company, and if such allocations are consistent with the principles of Section 704 of the Code.

(f) The Board of Directors may determine to depreciate or amortize the portion of an adjustment under Section 743(b) of the Code attributable to unrealized appreciation in any Adjusted Property (to the extent of the unamortized Book-Tax Disparity) using a predetermined rate derived from the depreciation or amortization method and useful life applied to the Company’s common basis of such property, despite any inconsistency of such approach with Treasury Regulation Section 1.167(c)-l(a)(6) or any successor regulations thereto. If the Board of Directors determines that such reporting position cannot reasonably be taken, the Board of Directors may adopt depreciation and amortization conventions under which all purchasers acquiring Units in the same month would receive depreciation and amortization deductions, based upon the same applicable rate as if they had purchased a direct interest in the Company’s property. If the Board of Directors chooses not to utilize such aggregate method, the Board of Directors may use any other depreciation and amortization conventions to preserve the uniformity of the intrinsic tax characteristics of any Member Interests, so long as such conventions would not have a material adverse effect on the Members or the Record Holders of any class or classes of Units.

(g) In accordance with Treasury Regulation 1.1245-1(e), any gain allocated to the Members upon the sale or other taxable disposition of any Company asset shall, to the extent possible, after taking into account other required allocations of gain pursuant to this Section 6.2, be characterized as Recapture Income in the same proportions and to the same extent as such Members (or their predecessors in interest) have been allocated any deductions directly or indirectly giving rise to the treatment of such gains as Recapture Income.

(h) All items of income, gain, loss, deduction and credit recognized by the Company for federal income tax purposes and allocated to the Members in accordance with the provisions hereof shall be determined without regard to any election under Section 754 of the Code that may be made by the Company; provided, however, that such allocations, once made, shall be adjusted (in the manner determined by the Board of Directors) to take into account those adjustments permitted or required by Sections 734 and 743 of the Code.

(i) Each item of Company income, gain, loss and deduction shall, for federal income tax purposes, be determined on an annual basis and prorated on a monthly basis and shall be allocated to the Members as of the opening of the New York Stock Exchange on the first Business Day of each month; provided, however, that (i) income, gain, loss and deduction recognized between the Closing Date and the Initial Public Offering shall be allocated to the Initial Investors, or their assigns, as if there were an interim closing of the books at the close of business the day before the Initial Public Offering and (ii) gain or loss

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on a sale or other disposition of any assets of the Company or any other extraordinary item of income or loss realized and recognized other than in the ordinary course of business, as determined by the Board of Directors, shall be allocated to the Members as of the opening of the New York Stock Exchange on the first Business Day of the month in which such gain or loss is recognized for federal income tax purposes. The Board of Directors may revise, alter or otherwise modify such methods of allocation to the extent permitted or required by Section 706 of the Code and the regulations or rulings promulgated thereunder.

(j) Allocations that would otherwise be made to a Member under the provisions of this Article VI shall instead be made to the beneficial owner of Units held by a nominee in any case in which the nominee has furnished the identity of such owner to the Company in accordance with Section 6031(c) of the Code or any other method determined by the Board of Directors.

Section 6.3 Requirement of Distributions; Distributions to Record Holders.

(a) Within 45 days following the end of each Quarter commencing with the first Quarter ending after the Initial Public Offering, an amount equal to 100% of Available Cash with respect to such Quarter shall, subject to Section 18-607 of the Delaware Act, be distributed in accordance with this Article VI by the Company to the Members as of the Record Date selected by the Board of Directors for such distribution (or by an Officer designated by our Board of Directors to select the Record Date for such distribution). All distributions required to be made under this Agreement shall be made subject to Sections 18-607 and 18-804 of the Delaware Act.

(b) Notwithstanding Section 6.3(a), in the event of the dissolution and liquidation of the Company, all receipts received during or after the Quarter in which the Liquidation Date occurs, other than from borrowings described in (a)(ii) of the definition of Available Cash, shall be applied and distributed solely in accordance with, and subject to the terms and conditions of, Section 10.3(a).

(c) The Board of Directors may treat taxes paid by the Company on behalf of, or amounts withheld with respect to, all or less than all of the Members, as a distribution of Available Cash to such Members.

(d) Each distribution in respect of a Member Interest shall be paid by the Company, directly or through the Transfer Agent or through any other Person or agent, only to the Record Holder of such Member Interest as of the Record Date set for such distribution. Such payment shall constitute full payment and satisfaction of the Company’s liability in respect of such payment, regardless of any claim of any Person who may have an interest in such payment by reason of an assignment or otherwise.

Section 6.4 Distributions of Available Cash. Available Cash with respect to any Quarter commencing with the first Quarter ending after the Initial Public Offering, subject to Section 18-607 of the Delaware Act and except as otherwise required by Section 5.7(b) in respect of other Company Securities issued pursuant thereto, shall be distributed 100% to all Unitholders in accordance with their respective Percentage Interests.

ARTICLE VII

MANAGEMENT AND OPERATION OF BUSINESS

Section 7.1 Board of Directors.

(a) Except as otherwise expressly provided in this Agreement, the business and affairs of the Company shall be managed by or under the direction of a Board of Directors (the “Board of Directors”). As provided in Section 7.4, the Board of Directors shall have the power and authority to appoint Officers of the Company. The Directors shall constitute “managers” within the meaning of the Delaware Act. No Member, by virtue of its status as such, shall have any management power over the business and affairs of the Company or actual or apparent authority to enter into, execute or deliver contracts on behalf of, or to

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otherwise bind, the Company. Except as otherwise specifically provided in this Agreement, the authority and functions of the Board of Directors, on the one hand, and of the Officers, on the other, shall be identical to the authority and functions of the board of directors and officers, respectively, of a corporation organized under the DGCL. In addition to the powers that now or hereafter can be granted to managers under the Delaware Act and to all other powers granted under any other provision of this Agreement subject to Section 7.3, the Board of Directors shall have full power and authority to do, and to direct the Officers to do, all things and on such terms as it determines to be necessary or appropriate to conduct the business of the Company, to exercise all powers set forth in Section 2.5 and to effectuate the purposes set forth in Section 2.4, including the following:

(i) 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 evidences of indebtedness, including indebtedness that is convertible into Company Securities, and the incurring of any other obligations;

(ii) the making of tax, regulatory and other filings, or rendering of periodic or other reports to governmental or other agencies having jurisdiction over the business or assets of the Company;

(iii) the acquisition, disposition, mortgage, pledge, encumbrance, hypothecation or exchange of any or all of the assets of the Company or the merger or other combination of the Company with or into another Person (the matters described in this clause (iii) being subject, however, to any prior approval that may be required by Section 7.3 and Article XII);

(iv) the use of the assets of the Company (including cash on hand) for any purpose consistent with the terms of this Agreement, including the financing of the conduct of the operations of the Company Group; subject to Section 7.6(a), the lending of funds to other Persons (including other Group Members); the repayment or guarantee of obligations of the Company Group and the making of capital contributions to any member of the Company Group;

(v) the negotiation, execution and performance of any contracts, conveyances or other instruments (including instruments that limit the liability of the Company under contractual arrangements to all or particular assets of the Company);

(vi) the distribution of Company cash;

(vii) the selection and dismissal of officers, employees, agents, outside attorneys, accountants, consultants and contractors and the determination of their compensation and other terms of employment or hiring, the creation and operation of employee benefit plans, employee programs and employee practices;

(viii) the maintenance of insurance for the benefit of the Company Group, the Members and any Indemnitees;

(ix) the formation of, or acquisition of an interest in, and the contribution of property and the making of loans to, any limited or general partnerships, joint ventures, corporations, limited liability companies or other relationships (including the acquisition of interests in, and the contributions of property to, any Group Member from time to time) subject to the restrictions set forth in Section 2.4;

(x) the control of any matters affecting the rights and obligations of the Company, 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;

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(xi) the indemnification of any Person against liabilities and contingencies to the extent permitted by law;

(xii) the entering into of listing agreements with any National Securities Exchange and the delisting of some or all of the Member Interests from, or requesting that trading be suspended on, any such exchange (subject to any prior approval that may be required under Section 4.6);

(xiii) the purchase, sale or other acquisition or disposition of Company Securities, or the issuance of options, rights, warrants and appreciation rights relating to Company Securities;

(xiv) the undertaking of any action in connection with the Company’s participation in any Group Member; and

(xv) the entering into of agreements with any of its Affiliates to render services to a Group Member.

(b) The Board of Directors shall initially consist of three natural Persons. Each Director shall be elected as provided in Section 7.1(c) and shall serve in such capacity until his or her successor has been duly elected and qualified or until such Director dies, resigns or is removed. A Director may resign at any time upon written notice to the Company. The Board of Directors may from time to time determine the number of Directors then constituting the whole Board of Directors, but the Board of Directors shall not decrease the number of Persons that constitute the whole Board of Directors if such decrease would shorten the term of any Director.

(c) The Persons comprising the Board of Directors shall be as follows: Thomas H. Blake, Lasse Wagnene and W. Richard Anderson. Such Persons shall serve as members of the Board of Directors until their successors are duly elected and qualified, or until their earlier death, resignation or removal. After the closing of the Initial Public Offering, directors shall be elected at each annual meeting of Members to serve for a term expiring at the next annual meeting of Members. The nomination of Persons to serve as Directors and the election of the Board of Directors shall be in accordance with Article XI hereof.

(d) Subject to applicable law and the rights of the holders of any series of Member Interests, vacancies existing on the Board of Directors (created by virtue of an increase in the size of the Board of Directors or resulting from the death, resignation or removal of a Director) may be filled only by the affirmative vote of a majority of the Directors then serving, even if less than a quorum. Any Director chosen to fill a vacancy shall hold office until the next annual meeting of Members and until his or her successor has been duly elected and qualified or until such Director’s earlier resignation or removal. Subject to the rights of the holders of any series of Member Interests, any Director, and the entire Board of Directors, may be removed from office at any time by the affirmative vote of the holders of at least 662¤3% of the Outstanding Units.

(e) Directors need not be Members. The Board of Directors may, from time to time and by the adoption of resolutions, establish qualifications for Directors.

(f) Unless otherwise required by the Delaware Act, other law or the provisions hereof,

(i) each member of the Board of Directors shall have one vote;

(ii) the presence at a meeting of the Board of Directors of a majority of the members of the Board of Directors shall constitute a quorum at any such meeting for the transaction of business; and

(iii) the act of a majority of the members of the Board of Directors present at a meeting of the Board of Directors at which a quorum is present shall be deemed to constitute the act of the Board of Directors.

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(g) Regular meetings of the Board of Directors and any committee thereof shall be held at such times and places as shall be designated from time to time by resolution of the Board of Directors or such committee. Notice of such regular meetings shall not be required. Special meetings of the Board of Directors or meetings of any committee thereof may be called by the Chairman of the Board or on the written request of a majority of the Directors or committee members, as applicable, to the Secretary, in each case on at least twenty-four hours personal, written, facsimile, electronic, telegraphic, cable or wireless notice to each Director or committee member, which notice may be waived by any Director or committee member. Any such notice, or waiver thereof, need not state the purpose of such meeting except as may otherwise be required by law. Attendance of a Director or committee member at a meeting (including pursuant to the last sentence of this Section 7.1(g)) shall constitute a waiver of notice of such meeting, except where such Director or committee member attends the meeting for the express purpose of objecting to the transaction of any business on the ground that the meeting is not lawfully called or convened. Any action required or permitted to be taken at a meeting of the Board of Directors, or any committee thereof, may be taken without a meeting, without prior notice and without a vote if a consent or consents in writing, setting forth the action so taken, are signed by all members of the Board of Directors or committee, as the case may be. Members of the Board of Directors or any committee thereof may participate in and hold a meeting by means of conference telephone, video conference or similar communications equipment by means of which all Persons participating in the meeting can hear each other, and participation in such meetings shall constitute presence in Person at the meeting.

(h) The Board of Directors shall, by resolution of a majority of the full Board of Directors, establish an Audit Committee and may designate one or more committees (which may include one or more of an audit committee, conflicts committee, compensation committee or governance and nominating committee), each committee to consist of one or more of the Directors, and the Board of Directors may from time to time adopt a charter for any of such committees. The Board of Directors may designate one or more Directors as alternate members of any committee, who may replace any absent or disqualified Director at any meeting of such committee. Any such committee, to the extent provided in the resolution of the Board of Directors or in this Agreement, shall have and may exercise all powers and authority of the Board of Directors in the management of the business and affairs of the Company; but no such committee shall have the power or authority in reference to the following matters: approving or adopting, or recommending to the Members, any action or matter expressly required by this Agreement or the Delaware Act to be submitted to the Members for approval or adopting, amending or repealing any provision of this Agreement. Unless specified by resolution of the Board of Directors, any committee designated pursuant to this Section 7.1(h) shall choose its own chairman, shall keep regular minutes of its proceedings and report the same to the Board of Directors when requested, and, subject to Section 7.1(h), shall fix its own rules or procedures and shall meet at such times and at such place or places as may be provided by such rules. At every meeting of any such committee, the presence of a majority of all the members thereof shall constitute a quorum and the affirmative vote of a majority of the members present at a meeting of which a quorum is present shall be necessary for the adoption by the committee of any resolution.

(i) The Board of Directors may elect one of its members as Chairman of the Board (the “Chairman of the Board”). The Chairman of the Board, if any, and if present and acting, shall preside at all meetings of the Board of Directors and of Members, unless otherwise directed by the Board of Directors. If the Board of Directors does not elect a Chairman or if the Chairman is absent from the meeting, the Chief Executive Officer, if present and a Director, or any other Director chosen by the Board of Directors, shall preside. In the absence of a Secretary, the chairman of the meeting may appoint any Person to serve as Secretary of the meeting.

(j) Unless otherwise restricted by law, the Board of Directors shall have the authority to fix the compensation of the Directors. The Directors may be paid their expenses, if any, of attendance at each

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meeting of the Board of Directors and may be paid a fixed sum for attendance at each meeting of the Board of Directors or paid a stated salary or paid other compensation as Director. No such payment shall preclude any Director from serving the Company in any other capacity and receiving compensation therefor. Members of special or standing committees may also be paid their expenses, if any, of and allowed compensation for attending committee meetings.

(k) Notwithstanding any other provision of this Agreement, any Group Member Agreement, the Delaware Act or any applicable law, rule or regulation, each of the Members and each other Person who may acquire an interest in Company Securities hereby (i) approves, ratifies and confirms the execution, delivery and performance by the parties thereto of this Agreement and the Group Member Agreement of each other Group Member, the Management Services Agreement, the Gathering Agreement and the other agreements that are related to the transactions contemplated by the Purchase Agreement; (ii) approves, ratifies and confirms the execution, delivery and performance by the parties thereto of any agreement determined by the Board of Directors to be necessary or appropriate in connection with the Initial Public Offering, including an omnibus agreement in customary form, an Underwriting Agreement in customary form and amendments to or restatements of the Management Services Agreement and the Gathering Agreement (the “Initial Public Offering Documents”); (iii) agrees that the Board of Directors (on its own or through any Officer of the Company) is authorized to execute, deliver and perform the agreements referred to in clauses (i) or (ii) of this sentence and the other agreements, acts, transactions and matters described in or contemplated by the Purchase Agreement or the Initial Public Offering Documents on behalf of the Company without any further act, approval or vote of the Members or the other Persons who may acquire an interest in Company Securities; and (iv) agrees that the execution, delivery or performance by the Company, any Group Member or any Affiliate of any of them of this Agreement or any agreement authorized or permitted under this Agreement shall not constitute a breach by the Board of Directors or any Officer of any duty that the Board of Directors or any Officer may owe the Company or the Members or any other Persons under this Agreement (or any other agreements) or of any duty stated or implied by law or equity.

Section 7.2 Certificate of Formation. The Certificate of Formation has been filed with the Secretary of State of the State of Delaware as required by the Delaware Act. The Board of Directors shall use all reasonable efforts to cause to be filed such other certificates or documents that it determines to be necessary or appropriate for the formation, continuation, qualification and operation of a limited liability company in the State of Delaware or any other state in which the Company may elect to do business or own property. To the extent that the Board of Directors determines such action to be necessary or appropriate, the Board of Directors shall direct the appropriate Officers of the Company to file amendments to and restatements of the Certificate of Formation and do all things to maintain the Company as a limited liability company under the laws of the State of Delaware or of any other state in which the Company may elect to do business or own property and any such Officer so directed shall be an “authorized person” of the Company within the meaning of the Delaware Act for purposes of filing any such certificate with the Secretary of State of the State of Delaware. Subject to the terms of Section 3.4(a), the Company shall not be required, before or after filing, to deliver or mail a copy of the Certificate of Formation, any qualification document or any amendment thereto to any Member.

Section 7.3 Restrictions on the Board of Directors’ Authority.

(a) Except as otherwise provided in this Agreement, the Board of Directors may not, without written approval of the specific act by holders of all of the Outstanding Member Interests or by other written instrument executed and delivered by holders of all of the Outstanding Member Interests subsequent to the date of this Agreement, take any action that is in breach or violation of this Agreement.

(b) Except as provided in Articles X and XII, the Board of Directors may not sell, exchange or otherwise dispose of all or substantially all of the assets of the Company Group, taken as a whole, in a

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single transaction or a series of related transactions (including by way of merger, consolidation, other combination or sale of ownership interests of the Company’s Subsidiaries) without the approval of holders of a Unit Majority; provided, however, that this provision shall not preclude or limit the Board of Directors’ ability to mortgage, pledge, hypothecate or grant a security interest in all or substantially all of the assets of the Company Group and shall not apply to any forced sale of any or all of the assets of the Company Group pursuant to the foreclosure of, or other realization upon, any such encumbrance.

Section 7.4 Officers.

(a) The Board of Directors shall have the power and authority to appoint such officers with such titles, authority and duties as determined by the Board of Directors. Such Persons so designated by the Board of Directors shall be referred to as “Officers.” Unless provided otherwise by resolution of the Board of Directors, the Officers shall have the titles, power, authority and duties described below in this Section 7.4.

(b) The Officers of the Company shall include a Chief Executive Officer, a President, Chief Financial Officer and a Secretary, and may also include a Chairman of the Board, Vice Chairman, Chief Operating Officer, Treasurer, one or more Vice Presidents (who may be further classified by such descriptions as “executive,” “senior,” “assistant” or otherwise, as the Board of Directors shall determine), one or more Assistant Secretaries and one or more Assistant Treasurers. Officers shall be elected by the Board of Directors, which shall consider that subject at its first meeting after every annual meeting of Members and as necessary to fill vacancies. Each Officer shall hold office until his or her successor is elected and qualified or until his or her earlier death, resignation or removal. Any number of offices may be held by the same Person. The compensation of Officers elected by the Board of Directors shall be fixed from time to time by the Board of Directors or a committee thereof or by such Officers as may be designated by resolution of the Board of Directors or a committee thereof.

(c) Any Officer may resign at any time upon written notice to the Company. Any Officer may be removed by the Board of Directors with or without cause at any time. The Board of Directors may delegate the power of removal as to Officers who have not been appointed by the Board of Directors. Such removal shall be without prejudice to a Person’s contract rights, if any, but the appointment of any Person as an Officer shall not of itself create contract rights.

(d) The President shall be the Chief Executive Officer of the Company unless the Board of Directors designates the Chairman of the Board as Chief Executive Officer. Subject to the control of the Board of Directors and the executive committee (if any), the Chief Executive Officer shall have general executive charge, management and control of the properties, business and operations of the Company with all such powers as may be reasonably incident to such responsibilities; he may employ and discharge employees and agents of the Company except such as shall be appointed by the Board of Directors, and he may delegate these powers; he may agree upon and execute all leases, contracts, evidences of indebtedness and other obligations in the name of the Company, and shall have such other powers and duties as designated in accordance with this Agreement and as from time to time may be assigned to him by the Board of Directors.

(e) If elected, the Chairman of the Board shall preside at all meetings of the Members and of the Board of Directors; and shall have such other powers and duties as designated in this Agreement and as from time to time may be assigned to him by the Board of Directors.

(f) Unless the Board of Directors otherwise determines, the President and the Chief Executive Officer (if other than the President) shall have the authority to agree upon and execute all leases, contracts, evidences of indebtedness and other obligations in the name of the Company; and, unless the Board of Directors otherwise determines, shall, in the absence of the Chairman of the Board or if there be no Chairman of the Board, preside at all meetings of the Members and (should he be a Director) of the

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Board of Directors; and he shall have such other powers and duties as designated in accordance with this Agreement and as from time to time may be assigned to him by the Board of Directors.

(g) In the absence of the President, or in the event of his inability or refusal to act, a Vice President designated by the Board of Directors shall perform the duties of the President, and when so acting shall have all the powers of and be subject to all the restrictions upon the President. In the absence of a designation by the Board of Directors of a Vice President to perform the duties of the President, or in the event of his absence or inability or refusal to act, the Vice President who is present and who is senior in terms of uninterrupted time as a Vice President of the Company shall so act. The Vice President shall perform such other duties and have such other powers as the Board of Directors may from time to time prescribe. Unless otherwise provided by the Board of Directors, each Vice President will have authority to act within his or her respective areas and to sign contracts relating thereto.

(h) The Chief Financial Officer shall have responsibility for the custody and control of all the funds and securities of the Company and shall have such other powers and duties as designated in this Agreement and as from time to time may be assigned to the Chief Financial Officer by the Board of Directors. The Chief Financial Officer shall perform all acts incident to the position of Chief Financial Officer, subject to the control of the Chief Executive Officer and the Board of Directors. Each Assistant Treasurer, if any, shall have the usual powers and duties pertaining to his office, together with such other powers and duties as designated in this Agreement and as from time to time may be assigned to him by the Chief Executive Officer or the Board of Directors. The Assistant Treasurer, if any, shall exercise the powers of the Chief Financial Officer during that Officer’s absence or inability or refusal to act. An Assistant Treasurer, if any, shall also perform such other duties as the Chief Financial Officer or the Board of Directors may assign to him.

(i) The Secretary shall issue all authorized notices for, and shall keep minutes of, all meetings of the Members and the Board of Directors. The Secretary shall have charge of the corporate books and shall perform such other duties as the Board of Directors may from time to time prescribe. In the absence or inability to act of the Secretary, any Assistant Secretary may perform all the duties and exercise all the powers of the Secretary. The performance of any such duty shall, in respect of any other Person dealing with the Company, be conclusive evidence of his power to act. An Assistant Secretary shall also perform such other duties as the Secretary or the Board of Directors may assign to him.

(j) The Board of Directors may from time to time delegate the powers or duties of any Officer to any other Officers, employees or agents, notwithstanding any provision hereof.

(k) Unless otherwise directed by the Board of Directors, the Chief Executive Officer, the President or any Officer of the Company authorized by the Chief Executive Officer shall have power to vote and otherwise act on behalf of the Company, in person or by proxy, at any meeting of Members of or with respect to any action of equity holders of any other entity in which the Company may hold securities and otherwise to exercise any and all rights and powers which the Company may possess by reason of its ownership of securities in such other entities.

Section 7.5 Outside Activities.

(a) It shall be deemed not to be a breach of any duty (including any fiduciary duty) existing hereunder, at law, in equity or otherwise or any other obligation of any type whatsoever of (i) any Director or Officer, or any Affiliate of any of the them, to engage in outside business interests and activities in preference to or to the exclusion of the Company or in direct competition with the Company; provided such Affiliate does not engage in such business or activity as a result of or using confidential or proprietary information provided by or on behalf of the Company to such Director or (ii) any Director, Officer or other employee of the Company to be a director, manager, officer, employee or consultant of any Member or any Affiliate of any Member of the Company; provided that the Board of Directors is advised of such

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other relationship and does not object thereto; and further, provided, that such Officer or employee does not engage in such business or activity as a result of or using confidential or proprietary information provided by or on behalf of the Company to such Person.

(b) None of the Directors or Officers shall have any obligation hereunder or as a result of any duty expressed or implied by law, in equity or otherwise, to present business opportunities to the Company that may become available to such Person or any of its Affiliates or of which the Person acquires knowledge other than while serving in the capacity as a Director or Officer. None of any Group Member, any Member or any other Person shall have any rights by virtue of a Person’s duties as a Director or Officer under this Agreement, any Group Member Agreement, applicable law or otherwise in any business ventures of any Director or Officer.

(c) Notwithstanding anything to the contrary in this Agreement, to the extent that any provisions of this Section 7.5 purport or are interpreted to have the effect of restricting, eliminating or otherwise modifying the duties (including fiduciary duties) that might otherwise, as a result of Delaware or other applicable law, be owed by the Directors, the Officers or any of their Affiliates to the Company and its Members, or to constitute a waiver or consent by the Members to any such fiduciary duty, such provisions in this Section 7.5 shall be deemed to have been approved by the Members, and the Members hereby agree that such provisions shall replace or eliminate such duties.

Section 7.6 Loans or Contributions from the Company or Group Members.

(a) The Company may lend or contribute to any Group Member, and any Group Member may borrow from the Company, funds on terms and conditions determined by the Board of Directors.

(b) No borrowing by any Group Member or the approval thereof by the Board of Directors shall be deemed to constitute a breach of any duty (including any fiduciary duty), hereunder or existing at law, in equity or otherwise, of the Board of Directors to the Company or the Members by reason of the fact that the purpose or effect of such borrowing is directly or indirectly to enable distributions to the Members.

Section 7.7 Indemnification.

(a) To the fullest extent permitted by law as it currently exists and to such greater extent as applicable law hereafter may permit, but subject to the limitations expressly provided in this Agreement, the Company shall indemnify, hold harmless and defend any Person who was or is a party or is threatened to be made a party to, or otherwise requires representation of counsel in connection with, any threatened, pending or completed action, suit or proceeding, whether civil, criminal, administrative or investigative (including an action by or in the right of the Company) by reason of the fact that such Person is an Indemnitee or by reason of any action alleged to have been taken or omitted in such capacity, against losses, expenses (including attorneys’ fees of counsel for such Indemnitee), judgments, fines, damages, penalties, interest, liabilities and amounts paid in settlement actually and reasonably incurred by the Person in connection with such action, suit or proceeding; provided, that the Indemnitee shall not be indemnified and held harmless if there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that, in respect of the matter for which the Indemnitee is seeking indemnification pursuant to Section 7.7(a), the Indemnitee acted in bad faith or engaged in fraud, willful misconduct or, in the case of a criminal matter, acted with knowledge that the Indemnitee’s conduct was unlawful. The termination of any action, suit or proceeding by judgment, order, settlement, conviction or upon a plea of nolo contendere or its equivalent, shall not, of itself, create a presumption that the Person acted in bad faith or engaged in fraud, willful misconduct or, with respect to any criminal action or proceeding, acted with the knowledge that the Person’s conduct was unlawful.

(b) To the extent an Indemnitee has been successful on the merits or otherwise in defense of any action, suit or proceeding referred to in Section 7.7(a), or in the defense of any claim, issue or matter

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therein, such Person shall be indemnified against expenses (including attorneys’ fees) actually and reasonably incurred by such Person in connection therewith.

(c) Expenses (including reasonable attorneys’ fees of counsel for such Indemnitee) incurred by an Indemnitee in defending any action, suit or proceeding referred to in Section 7.7(a) shall be paid by the Company, when and as incurred, in advance of the final disposition of such action, suit or proceeding and in advance of any determination that such Indemnitee is not entitled to be indemnified, upon receipt of an undertaking by or on behalf of such Indemnitee to repay such amount if it shall ultimately be determined by final judicial decision from which there is no further right to appeal (a “Final Adjudication”) that such Person is not entitled to be indemnified by the Company as authorized in this Section 7.7.

(d) The indemnification, advancement of expenses and other provisions of this Section 7.7 shall be in addition to any other rights to which an Indemnitee may be entitled under any agreement, pursuant to any vote of the holders of Outstanding Member Interests, as a matter of law or otherwise, both as to actions in the Indemnitee’s capacity as an Indemnitee and as to actions in any other capacity (including any capacity under the Underwriting Agreement), and shall continue as to an Indemnitee who has ceased to serve in such capacity and shall inure to the benefit of the heirs, successors, assigns and administrators of the Indemnitee.

(e) The Company may purchase and maintain insurance, on behalf of its Directors and Officers, and such other Persons as the Board of Directors shall determine, against any liability that may be asserted against or expense that may be incurred by such Person in connection with the Company’s activities or such Person’s activities on behalf of the Company, regardless of whether the Company would have the power to indemnify such Person against such liability under the provisions of this Agreement.

(f) For purposes of the definition of Indemnitee in Section 1.1, the Company shall be deemed to have requested a Person to serve as fiduciary of an employee benefit plan whenever the performance by such Person of his duties to the Company also imposes duties on, or otherwise involves services by, such Person to the plan or participants or beneficiaries of the plan; excise taxes assessed on an Indemnitee with respect to an employee benefit plan pursuant to applicable law shall constitute “fines” within the meaning of Section 7.7(a); and action taken or omitted by such Person with respect to any employee benefit plan in the performance of such Person’s duties for a purpose reasonably believed by him to be in the interest of the participants and beneficiaries of the plan shall be deemed to be for a purpose that is in, or not opposed to, the best interests of the Company.

(g) Any indemnification pursuant to this Section 7.7 shall be made only out of the assets of the Company, it being agreed that the Members shall not be personally liable for such indemnification and shall have no obligation to contribute or loan any monies or property to the Company to enable it to effectuate such indemnification.

(h) An Indemnitee shall not be denied indemnification in whole or in part under this Section 7.7 because the Indemnitee had an interest in the transaction with respect to which the indemnification applies if the transaction was otherwise permitted by the terms of this Agreement.

(i) If a claim under Section 7.7 is not paid in full by the Company within 60 days after a written claim has been received by the Company, except in the case of a claim for an advancement of expenses, in which case the applicable period shall be 20 days, the Indemnitee may at any time thereafter bring suit against the Company to recover the unpaid amount of the claim. If successful in whole or in part in any such suit, or in a suit brought by the Company to recover an advancement of expenses pursuant to the terms of an undertaking, the Indemnitee shall be entitled to be paid also the reasonable expenses of prosecuting or defending such suit. In (i) any suit brought by the Indemnitee to enforce a right to indemnification hereunder (but not in a suit brought by the Indemnitee to enforce a right to an advancement of expenses) it shall be a defense that, and (ii) in any suit brought by the Company to recover

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an advancement of expenses pursuant to the terms of an undertaking, the Company shall be entitled to recover such expenses upon a Final Adjudication that, the Indemnitee has not met any applicable standard for indemnification set forth in this Agreement. Neither the failure of the Company (including its Directors who are not parties to such action, a committee of such Directors, independent legal counsel, or its Members) to have made a determination prior to the commencement of such suit that indemnification of the Indemnitee is proper in the circumstances because the Indemnitee has met the applicable standard of conduct set forth in this Agreement, nor an actual determination by the Company (including its Directors who are not parties to such action, a committee of such Directors, independent legal counsel, or its Members) that the Indemnitee has not met the applicable standard of conduct shall create a presumption that the Indemnitee has not met the applicable standard of conduct, or, in the case of such a suit brought by the Indemnitee, be a defense to such suit. In any suit brought by the Indemnitee to enforce a right to indemnification or to an advancement of expenses hereunder, or brought by the Company to recover an advancement of expenses pursuant to the terms of an undertaking, the burden of proving that the Indemnitee is not entitled to be indemnified or to such advancement of expenses, under this Section 7.7 or otherwise shall be on the Company.

(j) The Company may indemnify any Person who was or is a party or is threatened to be made a party to any threatened, pending or completed action, suit or proceeding, whether civil, criminal, administrative or investigative (whether or not an action by or in the right of the Company) by reason of the fact that the Person is or was an employee (other than an Officer) or agent of the Company, or, while serving as an employee (other than an Officer) or agent of the Company is or was serving at the request of the Company as a manager, director, officer, employee, partner, fiduciary, trustee or agent of another Group Member or another Person to the extent (i) permitted by the laws of the State of Delaware as from time to time in effect, and (ii) authorized by the Board of Directors. The Company may, to the extent permitted by Delaware law and authorized by the Board of Directors, pay expenses (including attorneys’ fees) reasonably incurred by any such employee or agent in defending any civil, criminal, administrative or investigative action, suit or proceeding in advance of the final disposition of such action, suit or proceeding, upon such terms and conditions as the Board of Directors determine. The provisions of this Section 7.7(j) shall not constitute a contract right for any such employee or agent.

(k) The indemnification, advancement of expenses and other provisions of this Section 7.7 are for the benefit of the Indemnitees, their heirs, successors, assigns and administrators and shall not be deemed to create any rights for the benefit of any other Persons.

(l) Except to the extent otherwise provided in Section 7.7(j), the right to be indemnified and to receive advancement of expenses in this Section 7.7 shall be a contract right. No amendment, modification or repeal of this Section 7.7 or any provision hereof shall in any manner terminate, reduce or impair the right of any past, present or future Indemnitee to be indemnified by the Company, nor the obligations of the Company to indemnify any such Indemnitee under and in accordance with the provisions of this Section 7.7 as in effect immediately prior to such amendment, modification or repeal with respect to claims arising from or relating to matters occurring, in whole or in part, prior to such amendment, modification or repeal, regardless of when such claims may arise or be asserted.

Section 7.8 Exculpation of Liability of Indemnitees.

(a) Notwithstanding anything to the contrary set forth in this Agreement, no Indemnitee shall be liable to the Company, the Members or any other Persons who have acquired interests in Company Securities for losses sustained or liabilities incurred as a result of any act or omission of an Indemnitee unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that, in respect of the matter in question, the Indemnitee acted in bad faith or engaged in fraud, willful misconduct or, in the case of a criminal matter, acted with knowledge that the Indemnitee’s conduct was criminal.

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(b) Subject to its obligations and duties as Board of Directors set forth in this Article VII, the Board of Directors may exercise any of the powers granted to it by this Agreement and perform any of the duties imposed upon it hereunder either directly or by or through its agents, and the Board of Directors shall not be responsible for any misconduct or negligence on the part of any such agent appointed by the Board of Directors in good faith.

(c) To the extent that, at law or in equity, an Indemnitee has duties (including fiduciary duties) and liabilities relating thereto to the Company, to the Members or any other Persons who have acquired interests in Company Securities, none of the Managers and any other Indemnitee acting in connection with the Company’s business or affairs shall be liable to the Company, to any Member or any other Persons who have acquired interests in Company Securities for its good faith reliance on the provisions of this Agreement. The provisions of this Agreement, to the extent that they restrict or eliminate or otherwise modify the duties (including fiduciary duties) and liabilities of an Indemnitee otherwise existing at law or in equity, are agreed by the Members to replace such other duties and liabilities of such Indemnitee.

(d) Any amendment, modification or repeal of this Section 7.8 or any provision hereof shall be prospective only and shall not in any way affect the limitations on the liability of any Indemnitee under this Section 7.8 as in effect immediately prior to such amendment, modification or repeal with respect to claims arising from or relating to matters occurring, in whole or in part, prior to such amendment, modification or repeal, regardless of when such claims may arise or be asserted.

(e) An Indemnitee shall be fully protected in relying in good faith upon the records of the Company and upon information, opinions, reports or statements presented by a Director, Member or liquidating trustee, an Officer or employee of the Company or committees of the Company, Members or Directors, or by any other Person as to matters that the Member, Director or liquidating trustees reasonably believes are within such other Person’s professional or expert competence, including information, opinions, reports or statements as to the value and amount of the assets, liabilities, profits or losses of the Company, or the value and amount of assets or reserves or contracts, agreements or other undertakings that would be sufficient to pay claims and obligations of the Company or to make reasonable provision to pay such claims and obligations, or any other facts pertinent to the existence and amount of assets from which distributions to members or creditors might properly be paid.

Section 7.9 Resolution of Conflicts of Interest; Standards of Conduct and Modification of Duties.

(a) Unless otherwise expressly provided in this Agreement or any Group Member Agreement, whenever a potential conflict of interest exists or arises between any Affiliate of the Company (excluding the Company and any Group Member), on the one hand, and the Company or any Group Member, on the other, any resolution or course of action by the Board of Directors in respect of such conflict of interest shall be permitted and deemed approved by all Members, and shall not constitute a breach of this Agreement, of any Group Member Agreement, of any agreement contemplated herein or therein, or of any duty existing at law, in equity or otherwise, including any fiduciary duty, if the resolution or course of action in respect of such conflict of interest is (i) approved by Special Approval, (ii) approved by the vote of a majority of the Outstanding Units (excluding Units held by interested parties), (iii) on terms no less favorable to the Company than those generally being provided to or available from unrelated third parties or (iv) fair and reasonable to the Company, taking into account the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to the Company). The Board of Directors shall be authorized but not required in connection with its resolution of such conflict of interest to seek Special Approval of such resolution, and the Board of Directors may also adopt a resolution or course of action that has not received Special Approval. If Special Approval is not sought and the Board of Directors determines that the resolution or course of action taken with respect to a conflict of interest complies with the standards set forth in clause (iii) or (iv) of the second preceding sentence, then (A) such resolution or course of action shall be permitted and deemed approved by all

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Members, and shall not constitute a breach of this Agreement, of any Group Member Agreement, of any agreement contemplated herein or therein, or of any duty existing at law, in equity or otherwise, including any fiduciary duty and (B) it shall be presumed that, in making its decision, the Board of Directors acted in good faith, and in any proceeding brought by any Member or Assignee or by or on behalf of such Member or any other Member or the Company challenging such approval, the Person bringing or prosecuting such proceeding shall have the burden of overcoming such presumption. Notwithstanding anything to the contrary in this Agreement, the existence of the conflicts of interest described in the Registration Statement are hereby approved by all Members and shall not constitute a breach of this Agreement or any duty existing at law, in equity or otherwise.

(b) Whenever the Board of Directors or any Director or Officer makes a determination or takes or declines to take any action, whether under this Agreement, any Group Member Agreement or any other agreement contemplated hereby or otherwise, then, unless another express standard is provided for in this Agreement, the Board of Directors or such Director or Officer shall make such determination or take or decline to take such other action in good faith and shall not be subject to any other or different standards imposed by this Agreement, any Group Member Agreement, any other agreement contemplated hereby or under the Delaware Act or any other law, rule or regulation or at equity. In order for a determination or other action to be in “good faith” for purposes of this Agreement, the Person or Persons making such determination or taking or declining to take other action must believe that the determination or other action is in the best interests of the Company. No action taken by the Board of Directors, any Director or any Officer on behalf of the Company in good faith reliance on the provisions of this Agreement including this Article VII, shall constitute a breach of any duty (including any fiduciary duty or other similar duty) on the part of such Board of Directors or any Director or Officer, as the case may be. To the extent that the foregoing provisions have, or are construed to have, the effect of restricting, eliminating or otherwise modifying the duties and liabilities, including fiduciary duties, of the Directors or Officers otherwise existing at law, in equity or otherwise, such provisions and any restriction, elimination or modification (i) are, and shall be deemed to have been, approved and agreed to by the Members and (ii) are intended and agreed to replace and supersede such other duties and liabilities.

(c) Notwithstanding anything to the contrary in this Agreement prior to the dissolution of the Company, the Board of Directors shall have no duty or obligation, express or implied, to sell or otherwise dispose of any asset of the Company Group other than in the ordinary course of business.

(d) Except as expressly set forth in this Agreement or required by law, none of the Directors, nor any other Indemnitee shall have any duties or liabilities, including fiduciary duties, to the Company or any Member and the provisions of this Agreement, to the extent that they restrict, eliminate or otherwise modify the duties and liabilities, including fiduciary duties, of the Directors or any other Indemnitee otherwise existing at law or in equity, are agreed by the Members to replace such other duties and liabilities of the Directors or such other Indemnitee.

(e) The Members hereby authorize the Board of Directors, on behalf of the Company as a partner or member of a Group Member, to approve of actions by the Board of Directors or managing member of such Group Member similar to those actions permitted to be taken by the Board of Directors pursuant to this Section 7.9.

Section 7.10 Duties of Officers and Directors.

(a) The duties and obligations owed to the Company and to the Members by the Officers and Directors shall be as set forth in this Agreement.

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(b) A Director shall, in the performance of his duties, be fully protected in relying in good faith upon the records of the Company and on such information, opinions, reports or statements presented to the Company by any of the Company’s Officers or employees, or committees of the Board of Directors, or by any other Person as to matters the Director reasonably believes are within such other Person’s professional or expert competence and who has been selected with reasonable care by or on behalf of the Company.

(c) The Board of Directors shall have the right, in respect of any of its powers or obligations hereunder, to act through a duly appointed attorney or attorneys-in-fact or the duly authorized Officers of the Company.

Section 7.11 Purchase or Sale of Company Securities. The Board of Directors may cause the Company to purchase or otherwise acquire Company Securities.

Section 7.12 Reliance by Third Parties. Notwithstanding anything to the contrary in this Agreement, any Person dealing with the Company shall be entitled to assume that the Board of Directors and any Officer authorized by the Board of Directors to act on behalf of and in the name of the Company has full power and authority to encumber, sell or otherwise use in any manner any and all assets of the Company and to enter into any authorized contracts on behalf of the Company, and such Person shall be entitled to deal with the Board of Directors or any Officer as if it were the Company’s sole party in interest, both legally and beneficially. Each Member hereby waives, to the fullest extent permitted by law, any and all defenses or other remedies that may be available against such Person to contest, negate or disaffirm any action of the Board of Directors or any Officer in connection with any such dealing. In no event shall any Person dealing with the Board of Directors or any Officer or its representatives be obligated to ascertain that the terms of this Agreement have been complied with or to inquire into the necessity or expedience of any act or action of the Board of Directors or any Officer or its representatives. Each and every certificate, document or other instrument executed on behalf of the Company by the Board of Directors or any Officer or its representatives shall be conclusive evidence in favor of any and every Person relying thereon or claiming thereunder that (a) at the time of the execution and delivery of such certificate, document or instrument, this Agreement was in full force and effect, (b) the Person executing and delivering such certificate, document or instrument was duly authorized and empowered to do so for and on behalf of the Company and (c) such certificate, document or instrument was duly executed and delivered in accordance with the terms and provisions of this Agreement and is binding upon the Company.

ARTICLE VIII

BOOKS, RECORDS, ACCOUNTING AND REPORTS

Section 8.1 Records and Accounting. The Board of Directors shall keep or cause to be kept at the principal office of the Company appropriate books and records with respect to the Company’s business, including all books and records necessary to provide to the Members any information required to be provided pursuant to this Agreement. Any books and records maintained by or on behalf of the Company in the regular course of its business, including the record of the Record Holders or Assignees of Units or other Company Securities, books of account and records of Company proceedings, may be kept on, or be in the form of, computer disks, hard drives, punch cards, magnetic tape, photographs, micrographics or any other information storage device; provided, that the books and records so maintained are convertible into clearly legible written form within a reasonable period of time. The books of the Company shall be maintained, for financial reporting purposes, on an accrual basis in accordance with U.S. GAAP.

Section 8.2 Fiscal Year. The fiscal year of the Company shall be a fiscal year ending December 31, or such date as determined by the Board of Directors.

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Section 8.3 Reports.

(a) As soon as practicable, but in no event later than 120 days after the close of each fiscal year of the Company, the Board of Directors shall use its reasonable best efforts to cause to be mailed or made available by any reasonable means (including posting on the Company’s website) to each Record Holder of a Unit as of a date selected by the Board of Directors, an annual report containing financial statements of the Company for such fiscal year of the Company, presented in accordance with U.S. GAAP, including a balance sheet and statements of operations, equity and cash flows. Following the Initial Public Offering, such statements shall be required to be audited by a registered public accounting firm selected by the Board of Directors.

(b) As soon as practicable, but in no event later than 90 days after the close of each Quarter except the last Quarter of each fiscal year, the Board of Directors shall use its reasonable best efforts to cause to be mailed or made available by any reasonable means (including posting on or accessible through the Company’s website) to each Record Holder of a Unit as of a date selected by the Board of Directors, a report containing unaudited financial statements of the Company and such other information as may be required by applicable law, regulation or rule of any National Securities Exchange on which the Common Units are listed or admitted for trading, or as the Board of Directors determines to be necessary or appropriate.

ARTICLE IX

TAX MATTERS

Section 9.1 Tax Returns and Information. The Company shall timely file all returns of the Company that are required for federal, state and local income tax purposes on the basis of the accrual method and a taxable year ending on December 31. The tax information reasonably required by Record Holders for federal and state income tax reporting purposes with respect to a taxable year shall be furnished to them within 90 days of the close of the calendar year in which the Company’s taxable year ends. The classification, realization and recognition of income, gain, losses and deductions and other items shall be on the accrual method of accounting for federal income tax purposes.

Section 9.2 Tax Elections.

(a) The Company shall make the election under Section 754 of the Code in accordance with applicable regulations thereunder, subject to the reservation of the right to seek to revoke any such election upon the Board of Directors’ determination that such revocation is in the best interests of the Members. Notwithstanding any other provision herein contained, for the purposes of computing the adjustments under Section 743(b) of the Code, the Board of Directors shall be authorized (but not required) to adopt a convention whereby the price paid by a transferee of a Member Interest will be deemed to be the lowest quoted closing price of the Member Interests on any National Securities Exchange on which such Member Interests are traded during the calendar month in which such transfer is deemed to occur pursuant to Section 6.2(i) without regard to the actual price paid by such transferee.

(b) The Company shall elect to deduct expenses incurred in organizing the Company as provided in Section 709 of the Code.

(c) Except as otherwise provided herein, the Board of Directors shall determine whether the Company should make any other elections permitted by the Code.

Section 9.3 Tax Controversies. Subject to the provisions hereof, the Board of Directors shall designate one Officer who is a Member as the Tax Matters Partner (as defined in the Code). The Tax Matters Partner is authorized and required to represent the Company (at the Company’s expense) in connection with all examinations of the Company’s affairs by tax authorities, including resulting

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administrative and judicial proceedings, and to expend Company funds for professional services and costs associated therewith. Each Member agrees to cooperate with the Tax Matters Partner and to do or refrain from doing any or all things reasonably required by the Tax Matters Partner to conduct such proceedings.

Section 9.4 Withholding. Notwithstanding any other provision of this Agreement, the Board of Directors is authorized to take any action that may be required to cause the Company and other Group Members to comply with any withholding requirements established under the Code or any other federal, state or local law including pursuant to Sections 1441, 1442, 1445 and 1446 of the Code. To the extent that the Company is required or elects to withhold and pay over to any taxing authority any amount resulting from the allocation or distribution of income to any Member (including by reason of Section 1446 of the Code), the Board of Directors may treat the amount withheld as a distribution of cash pursuant to Section 6.3 in the amount of such withholding from such Member.

ARTICLE X

DISSOLUTION AND LIQUIDATION

Section 10.1 Dissolution. The Company shall not be dissolved by the admission of Substituted Members or Additional Members. The Company shall dissolve, and its affairs shall be wound up, upon:

(a) an election to dissolve the Company by the Board of Directors that is approved by the holders of a Unit Majority;

(b) the sale, exchange or other disposition of all or substantially all of the assets and properties of the Company Group; or

(d) at such time as there are no Members, unless the Company is continued without dissolution in accordance with the Delaware Act.

Section 10.2 Liquidator. Upon dissolution of the Company, the Board of Directors shall select one or more Persons to act as Liquidator. The Liquidator (if other than the Board of Directors) shall be entitled to receive such compensation for its services as may be approved by holders of a Unit Majority. The Liquidator (if other than the Board of Directors) shall agree not to resign at any time without 15 days’ prior notice and may be removed at any time, with or without cause, by notice of removal approved by holders of a Unit Majority. Upon dissolution, death, incapacity, removal or resignation of the Liquidator, a successor and substitute Liquidator (who shall have and succeed to all rights, powers and duties of the original Liquidator) shall within 30 days thereafter be approved by holders of a Unit Majority. The right to approve a successor or substitute Liquidator in the manner provided herein shall be deemed to refer also to any such successor or substitute Liquidator approved in the manner herein provided. Except as expressly provided in this Article X, the Liquidator approved in the manner provided herein shall have and may exercise, without further authorization or consent of any of the parties hereto, all of the powers conferred upon the Board of Directors under the terms of this Agreement (but subject to all of the applicable limitations, contractual and otherwise, upon the exercise of such powers, other than the limitation on sale set forth in Section 7.3(b)) necessary or appropriate to carry out the duties and functions of the Liquidator hereunder for and during the period of time required to complete the winding up and liquidation of the Company as provided for herein.

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Section 10.3 Liquidation. The Liquidator shall proceed to dispose of the assets of the Company, discharge its liabilities, and otherwise wind up its affairs in such manner and over such period as determined by the Liquidator, subject to Section 18-804 of the Delaware Act and the following:

(a) The assets may be disposed of by public or private sale or by distribution in kind to one or more Members on such terms as the Liquidator and such Member or Members may agree. If any property is distributed in kind, the Member receiving the property shall be deemed for purposes of Section 10.3(c) to have received cash equal to its fair market value; and contemporaneously therewith, appropriate cash distributions must be made to the other Members. Notwithstanding anything to the contrary contained in this Agreement, the Members understand and acknowledge that a Member may be compelled to accept a distribution of any asset in kind from the Company despite the fact that the percentage of the asset distributed to such Member exceeds the percentage of that asset which is equal to the percentage in which such Member shares in distributions from the Company. The Liquidator may defer liquidation or distribution of the Company’s assets for a reasonable time if it determines that an immediate sale or distribution of all or some of the Company’s assets would be impractical or would cause undue loss to the Members. The Liquidator may distribute the Company’s assets, in whole or in part, in kind if it determines that a sale would be impractical or would cause undue loss to the Members.

(b) Liabilities of the Company include amounts owed to the Liquidator as compensation for serving in such capacity (subject to the terms of Section 10.2) and amounts to Members otherwise than in respect of their distribution rights under Article VI. With respect to any liability that is contingent, conditional or unmatured or is otherwise not yet due and payable, the Liquidator shall either settle such claim for such amount as it thinks appropriate or establish a reserve of cash or other assets to provide for its payment. When paid, any unused portion of the reserve shall be distributed as additional liquidation proceeds.

(c) All property and all cash in excess of that required to discharge liabilities as provided in Section 10.3(b) shall be distributed to the Members in accordance with, and to the extent of, the positive balances in their respective Capital Accounts, as determined after taking into account all Capital Account adjustments (other than those made by reason of distributions pursuant to this Section 10.3(c)) for the taxable year of the Company during which the liquidation of the Company occurs (with such date of occurrence being determined pursuant to Treasury Regulation Section 1.704-1(b)(2)(ii)(g)), and such distribution shall be made by the end of such taxable year (or, if later, within 90 days after said date of such occurrence).

Section 10.4 Cancellation of Certificate of Formation. Upon the completion of the distribution of Company cash and property as provided in Section 10.3 in connection with the liquidation of the Company, the Certificate of Formation and all qualifications of the Company as a foreign limited liability company in jurisdictions other than the State of Delaware shall be canceled and such other actions as may be necessary to terminate the Company shall be taken.

Section 10.5 Return of Contributions. None of any member of the Board of Directors or any Officer will be personally liable for, or have any obligation to contribute or loan any monies or property to the Company to enable it to effectuate, the return of the Capital Contributions of the Members or Unitholders, or any portion thereof, it being expressly understood that any such return shall be made solely from Company assets. Members may not resign or withdraw from the Company prior to the dissolution and winding up of the Company, provided that the transfer of any Member Interest shall not constitute a breach or violation of this provision.

Section 10.6 Waiver of Partition. To the maximum extent permitted by law, each Member hereby waives any right to partition of the Company property.

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Section 10.7 Capital Account Restoration. No Member shall have any obligation to restore any negative balance in its Capital Account upon liquidation of the Company.

ARTICLE XI

AMENDMENT OF AGREEMENT; MEETINGS OF MEMBERS; RECORD DATE

Section 11.1 Amendment of Limited Liability Company Agreement.

(a) General Amendments. Except as provided in Section 11.1(b) and Section 11.1(c), the Board of Directors may amend any of the terms of this Agreement but only in compliance with the terms, conditions and procedures set forth in this Section 11.1(a). If the Board of Directors desires to amend any provision of this Agreement other than pursuant to Section 11.1(c), then it shall first adopt a resolution setting forth the amendment proposed, declaring its advisability and either calling a special meeting of the Members entitled to vote in respect thereof for the consideration of such amendment or directing that the amendment proposed be considered at the next annual meeting of the Members. Amendments to this Agreement may be proposed only by or with the consent of the Board of Directors. Such special or annual meeting shall be called and held upon notice in accordance with Section 11.3 and Section 11.4 of this Agreement. The notice of such meeting shall set forth such amendment in full or a brief summary of the changes to be effected thereby, as the Board of Directors shall deem advisable. At the meeting, a vote of Members entitled to vote thereon shall be taken for and against the proposed amendment. Subject to Section 11.2(d), a proposed amendment shall be effective upon its approval by a Unit Majority, unless a greater percentage is required under this Agreement.

(b) Super-Majority Amendments. Notwithstanding Section 11.1(a) but subject to Section 11.1(c), the affirmative vote of the holders of at least 75% of all Outstanding Units, voting together as a single class, shall be required to alter, amend, adopt any provision inconsistent with or repeal this Section 11.1(b), Section 11.2, Section 11.3(d), Section 11.8(b), Section 11.8(c), Section 11.10 or Section 11.13.

(c) Amendments to be Adopted Solely by the Board of Directors. Notwithstanding Section 11.1(a) and Section 11.1(b), the Board of Directors, without the approval of any Member or holder of any Company Securities, may amend any provision of this Agreement, and execute, swear to, acknowledge, deliver, file and record whatever documents may be required in connection therewith, to reflect:

(i) a change in the name of the Company, the location of the principal place of business of the Company, the registered agent of the Company or the registered office of the Company;

(ii) admission, substitution, withdrawal or removal of Members in accordance with this Agreement;

(iii) a change that the Board of Directors determines to be necessary or appropriate to qualify or continue the qualification of the Company as a limited liability company under the laws of any state or to ensure that the Group Members will not be treated as associations taxable as corporations or otherwise taxed as entities for federal income tax purposes;

(iv) a change that the Board of Directors determines (A) does not adversely affect the Members (including any particular class of Member Interests as compared to other classes of Member Interests) in any material respect, (B) to be necessary or appropriate to (1) 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 (including the Delaware Act) or (2) facilitate the trading of the Units (including the division of any class or classes of Outstanding Units into different classes to facilitate uniformity of tax consequences within such classes of Units) or comply with any rule, regulation, guideline or

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requirement of any National Securities Exchange on which the Units are or will be listed for trading, compliance with any of which the Board of Directors deems to be in the best interests of the Company and the Members, (C) to be necessary or appropriate in connection with action taken by the Board of Directors pursuant to Section 5.9 or (D) is required to effect the intent expressed in the Registration Statement or the intent of the provisions of this Agreement or is otherwise contemplated by this Agreement;

(v) a change in the fiscal year or taxable year of the Company and any other changes that the Board of Directors determines to be necessary or appropriate as a result of a change in the fiscal year or taxable year of the Company including, if the Board of Directors shall so determine, a change in the definition of “Quarter” and the dates on which distributions are to be made by the Company;

(vi) an amendment that is necessary, in the Opinion of Counsel, to prevent the Company or its Directors, Officers, trustees or agents from in any manner being subjected to the provisions of the Investment Company Act of 1940, as amended, or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974, as amended, regardless of whether such are substantially similar to plan asset regulations currently applied or proposed by the United States Department of Labor;

(vii) subject to the terms of Section 5.5, an amendment that the Board of Directors determines to be necessary or appropriate in connection with the authorization of issuance of any class or series of Company Securities pursuant to Section 5.4;

(viii) any amendment expressly permitted in this Agreement to be made by the Board of Directors acting alone;

(ix) an amendment effected, necessitated or contemplated by a Merger Agreement or Plan of Conversion approved in accordance with Section 12.3;

(x) an amendment that the Board of Directors determines to be necessary or appropriate to reflect and account for the formation by the Company of, or investment by the Company in, any corporation, partnership, joint venture, limited liability company or other entity, in connection with the conduct by the Company of activities permitted by the terms of Section 2.4;

(xi) a merger, consolidation, conversion or conveyance pursuant to Section 12.3(d);

(xii) an amendment that requires, in connection with a transfer of Member Interests, the Assignees of Member Interests to provide a statement, certification or other proof to the Company regarding such Assignee’s status as an Eligible Citizen; or

(xiii) any other amendments substantially similar to the foregoing.

Section 11.2 Amendment Requirements.

(a) Notwithstanding the provisions of Section 11.1, no provision of this Agreement that establishes a percentage of Outstanding Units required to take any action shall be amended, altered, changed, repealed or rescinded in any respect that would have the effect of reducing such voting percentage unless such amendment is approved by the affirmative vote of holders of Outstanding Units whose aggregate Outstanding Units constitute not less than the voting requirement sought to be reduced.

(b) Notwithstanding the provisions of Section 11.1, no amendment to this Agreement may (i) enlarge the obligations of any Member without its consent, unless such shall be deemed to have occurred as a result of an amendment approved pursuant to Section 11.2(c), (ii) change Section 10.1(a), (iii) change the term of the Company, or (iv) except as set forth in Section 10.1(a), give any Person the right to dissolve the Company.

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(c) Except as provided in Section 12.3, and without limitation of the Board of Directors’ authority to adopt amendments to this Agreement without the approval of any Members as contemplated in Section 11.1 (including Section 11.1(c)(vii)), any amendment that would have a material adverse effect on the rights or preferences of any then Outstanding class of Member Interests in relation to other classes of Member Interests must be approved by the holders of not less than a majority of the Outstanding Interests of the class affected, provided that amending this Agreement to create a new class or series of Company Securities pursuant to Section 5.5 with relative rights, powers, preferences and duties that are senior or prior to, or pari passu with, the relative rights, powers, preferences or duties of any then Outstanding Member Interests shall not be deemed to cause such a material adverse effect.

(d) Notwithstanding any other provision of this Agreement, except for amendments pursuant to Section 11(b) and Section 11.1(c) and except as otherwise provided by Section 12.3(b), no amendments shall become effective without the approval of the holders of at least 90% of the Outstanding Units voting as a single class unless the Company obtains an Opinion of Counsel to the effect that such amendment will not affect the limited liability of any Member under applicable law.

Section 11.3 Unitholder Meetings.

(a) All acts of Members to be taken hereunder shall be taken in the manner provided in this Article XI. An annual meeting of the Members for the election of Directors and for the transaction of such other business as may properly come before the meeting shall be held at such time and place as the Board of Directors shall specify, which date shall be within 13 months of the last annual meeting of Members. If authorized by the Board of Directors, and subject to such guidelines and procedures as the Board of Directors may adopt, Members and proxyholders not physically present at a meeting of Members, may by means of remote communication participate in such meeting, and be deemed present in person and vote at such meeting provided that the Company shall implement reasonable measures to verify that each Person deemed present and permitted to vote at the meeting by means of remote communication is a Member or proxyholder, to provide such Members or proxyholders a reasonable opportunity to participate in the meeting and to record the votes or other action made by such Members or proxyholders.

(b) A failure to hold the annual meeting of the Members at the designated time or to elect a sufficient number of Directors to conduct the business of the Company shall not affect otherwise valid acts of the Company or work a forfeiture or dissolution of the Company. If the annual meeting for election of Directors is not held on the date designated therefor, the Directors shall cause the meeting to be held as soon as is convenient. If there is a failure to hold the annual meeting for a period of 30 days after the date designated for the annual meeting, or if no date has been designated, for a period of 13 months after the latest to occur of the date of this Agreement or its last annual meeting, the Delaware Court of Chancery may summarily order a meeting to be held upon the application of any Member or Director. The Outstanding Units present at such meeting, either in person or by proxy, and entitled to vote thereat, shall constitute a quorum for the purpose of such meeting, notwithstanding any provision of this Agreement to the contrary. The Delaware Court of Chancery may issue such orders as may be appropriate, including orders designating the time and place of such meeting, the record date for determination of Unitholders entitled to vote, and the form of notice of such meeting.

(c) All elections of Directors will be by written ballots; if authorized by the Board of Directors, such requirement of a written ballot shall be satisfied by a ballot submitted by electronic transmission, provided that any such electronic transmission must either set forth or be submitted with information from which it can be reasonably determined that the electronic transmission was authorized by the Member or proxyholder.

(d) Special meetings of the Members may be called only by a majority of the Board of Directors. No Members or group of Members, acting in its or their capacity as Members, shall have the right to call a special meeting of the Members.

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Section 11.4 Notice of Meetings of Members.

(a) Notice, stating the place, day and hour of any annual or special meeting of the Members, as determined by the Board of Directors, and (i) in the case of a special meeting of the Members, the purpose or purposes for which the meeting is called, as determined by the Board of Directors or (ii) in the case of an annual meeting, those matters that the Board of Directors, at the time of giving the notice, intends to present for action by the Members, shall be delivered by the Company not less than 10 calendar days nor more than 60 calendar days before the date of the meeting, in a manner and otherwise in accordance with Section 14.1 to each Record Holder who is entitled to vote at such meeting. Such further notice shall be given as may be required by Delaware law. The notice of any meeting of the Members at which directors are to be elected shall include the name of any nominee or nominees who, at the time of the notice, the Board of Directors intends to present for election. Only such business shall be conducted at a special meeting of Members as shall have been brought before the meeting pursuant to the Company’s notice of meeting. Any previously scheduled meeting of the Members may be postponed, and any special meeting of the Members may be canceled, by resolution of the Board of Directors upon public notice given prior to the date previously scheduled for such meeting of the Members.

(b) The Board of Directors shall designate the place of meeting for any annual meeting or for any special meeting of the Members. If no designation is made, the place of meeting shall be the principal office of the Company.

Section 11.5 Record Date. For purposes of determining the Members entitled to notice of or to vote at a meeting of the Members or to give approvals without a meeting as provided in Section 11.10, the Board of Directors may set a Record Date, which shall not be less than 10 nor more than 60 days before (a) the date of the meeting (unless such requirement conflicts with any rule, regulation, guideline or requirement of any National Securities Exchange on which the Units are listed for trading, in which case the rule, regulation, guideline or requirement of such exchange shall govern) or (b) in the event that approvals are sought without a meeting, the date by which Members are requested by the Board of Directors to give such approvals. If no Record Date is fixed by the Board of Directors, then (a) the Record Date for determining Members entitled to notice of or to vote at a meeting of Members shall be at the close of business on the day next preceding the day on which notice is given and (b) the Record Date for determining the Members entitled to give approvals without a meeting shall be the date the first written approval is deposited with the Company in care of the Board of Directors. A determination of Members of record entitled to notice of or to vote at a meeting of Members shall apply to any adjournment or postponement of the meeting; provided, however, that the Board of Directors may fix a new Record Date for the adjourned or postponed meeting.

Section 11.6 Adjournment. The Chairman of the Board, or, if the Chief Executive Officer is acting as the chairman of such meeting, the Chief Executive Officer, may adjourn any meeting of the Members, whether for lack of a quorum or any other reason. When a meeting is adjourned to another time or place, notice need not be given of the adjourned meeting and a new Record Date need not be fixed, if the time and place thereof are announced at the meeting at which the adjournment is taken, unless such adjournment shall be for more than 30 days. At the adjourned meeting, the Company may transact any business that might have been transacted at the original meeting. If the adjournment is for more than 30 days or if a new Record Date is fixed for the adjourned meeting, a notice of the adjourned meeting shall be given in accordance with this Article XI.

Section 11.7 Waiver of Notice; Approval of Meeting. Whenever notice to the Members is required to be given under this Agreement, a written waiver, signed by the Person entitled to notice, whether before or after the time stated therein, shall be deemed equivalent to notice. Attendance of a Person at any such meeting of the Members shall constitute a waiver of notice of such meeting, except when the Person attends a meeting for the express purpose of objecting at the beginning of the meeting, to the transaction

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of any business because the meeting is not lawfully called or convened. Neither the business to be transacted at, nor the purpose of, any regular or special meeting of the Members need be specified in any written waiver of notice unless so required by resolution of the Board of Directors. All waivers and approvals shall be filed with the Company records or made part of the minutes of the meeting.

Section 11.8 Quorum; Required Vote for Member Action; Voting for Directors.

(a) At any meeting of the Members, the holders of a majority of the Outstanding Units or Member Interests of each class then Outstanding and entitled to vote, represented in person or by proxy, shall constitute a quorum of such class or classes unless any such action by the Members requires approval by holders of a greater percentage of Outstanding Units or Member Interests, in which case the quorum shall be such greater percentage. The submission of matters to Members for approval and the election of Directors shall occur only at a meeting of the Members duly called and held in accordance with this Agreement at which a quorum is present; provided, however, that the Members present at a duly called or held meeting at which a quorum is present may continue to transact business until adjournment, notwithstanding the withdrawal of enough Members to leave less than a quorum, if any action taken (other than adjournment) is approved by the required percentage of Interests specified in this Agreement. In the absence of a quorum any meeting of Members may be adjourned from time to time by the chairman of the meeting to another place or time.

(b) Each Outstanding Unit shall be entitled to one vote per Unit on all matters submitted to Members for approval and in the election of Directors.

(c) Except as otherwise provided in this Agreement, all matters submitted to Members for approval shall be determined by a majority of the votes cast affirmatively or negatively by Members holding Outstanding Units unless a greater percentage is required with respect to such matter under the Delaware Act, under the rules of any National Securities Exchange on which the Common Units are listed for trading, or under the provisions of this Agreement, in which case the approval of Members holding Outstanding Units that in the aggregate represent at least such greater percentage shall be required.

(d) Except as otherwise provided in this Agreement, directors will be elected by a plurality of the votes cast for a particular position.

Section 11.9 Conduct of a Meeting; Member Lists.

(a) The Board of Directors shall have full power and authority concerning the manner of conducting any meeting of the Members, including the determination of Persons entitled to vote, the existence of a quorum, the satisfaction of the requirements of this Article XI, the conduct of voting, the validity and effect of any proxies and subject to Section 11.12(d), the determination of any controversies, votes or challenges arising in connection with or during the meeting or voting. The Board of Directors shall have the power to designate a Person to serve as chairman of any meeting and shall further designate a Person to take the minutes of any meeting. All minutes shall be kept with the records of the Company maintained by the Board of Directors. The Board of Directors may make such other regulations consistent with applicable law and this Agreement as it may deem advisable concerning the conduct of any meeting of the Members, including regulations in regard to the appointment of proxies, the appointment and duties of inspectors of votes, the submission and examination of proxies and other evidence of the right to vote.

(b) A complete list of Members entitled to vote at any meeting of Members, arranged in alphabetical order for each class of Member Interests and showing the address of each such Member and the number of Outstanding Units registered in the name of such Member, shall be open to the examination of any Member, for any purpose germane to the meeting, during ordinary business hours, for a period of at least 10 days before the meeting, at the principal place of business of the Company. The Member list shall also be produced and kept at the time and place of the meeting during the whole time thereof, and may be inspected by any Member who is present.

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Section 11.10 Action Without a Meeting. No action permitted or required to be taken at a meeting of Members may be taken by written consent or by any other means or manner than a meeting of Members called and conducted in accordance with this Agreement.

Section 11.11 Voting and Other Rights.

(a) Only those Record Holders of Outstanding Units and Member Interests on the Record Date established pursuant to Section 11.5 shall be entitled to notice of, and to vote at, a meeting of Members or to act with respect to matters as to which the holders of the Outstanding Units and Member Interests have the right to vote or to act. All references in this Agreement to votes of, or other acts that may be taken by, the Outstanding Units and Member Interests shall be deemed to be references to the votes or acts of the Record Holders of such Outstanding Units and Member Interests.

(b) With respect to Outstanding Units or Member Interests that are held for a Person’s account by another Person (such as a broker, dealer, bank, trust company or clearing corporation, or an agent of any of the foregoing), in whose name such Outstanding Units or Member Interests are registered, such other Person shall, in exercising the voting rights in respect of such Outstanding Units or Member Interests on any matter, and unless the arrangement between such Persons provides otherwise, vote such Outstanding Units or Member Interests in favor of, and at the direction of, the Person who is the beneficial owner, and the Company shall be entitled to assume it is so acting without further inquiry. The provisions of this Section 11.11(b) (as well as all other provisions of this Agreement) are subject to the provisions of Section 4.3.

Section 11.12 Proxies and Voting.

(a) At any meeting of the Members, every holder of an Outstanding Unit or Member Interest entitled to vote may vote in person or by proxy authorized by an instrument in writing or by a transmission permitted by law filed in accordance with the procedure established for the meeting. Any copy, facsimile telecommunication or other reliable reproduction of the writing or transmission created pursuant to this paragraph may be substituted or used in lieu of the original writing or transmission for any and all purposes for which the original writing or transmission could be used, provided that such copy, facsimile telecommunication or other reproduction shall be a complete reproduction of the entire original writing or transmission.

(b) The Company may, and to the extent required by law, shall, in advance of any meeting of Members, appoint one or more inspectors to act at the meeting and make a written report thereof. The Company may designate one or more alternate inspectors to replace any inspector who fails to act. If no inspector or alternate is able to act at a meeting of Members, the Person presiding at the meeting may, and to the extent required by law, shall, appoint one or more inspectors to act at the meeting. Each inspector, before entering upon the discharge of his or her duties, shall take and sign an oath faithfully to execute the duties of inspector with strict impartiality and according to the best of his or her ability. Every vote taken by ballots shall be counted by a duly appointed inspector or inspectors.

(c) With respect to the use of proxies at any meeting of Members, the Company shall be governed by paragraphs (b), (c), (d) and (e) of Section 212 of the DGCL and other applicable provisions of the DGCL, as though the Company were a Delaware corporation and as though the Members were stockholders of a Delaware corporation.

(d) With respect to any contested matter relating to any election, appointment, removal or resignation of any Director, to the fullest extent permitted by law, the Company shall be governed by Section 225 of the DGCL and any other applicable provision of the DGCL, as though the Company were a Delaware corporation.

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Section 11.13 Notice of Member Business and Nominations.

(a) Nominations of Persons for election to the Board of Directors of the Company and the proposal of business to be considered by the Members may be made at an annual meeting of Members (i) pursuant to the Company’s notice of meeting delivered pursuant to Section 11.4 of this Agreement, (ii) by or at the direction of the Board of Directors, (iii) for nominations to the Board of Directors only, by any holder of Outstanding Units who is entitled to vote at the meeting, who complied with the notice procedures set forth in paragraph (b) or (d) of this Section 11.13 and who was a Record Holder of a sufficient number of Outstanding Units as of the Record Date for such meeting to elect one or more members to the Board of Directors assuming that such holder cast all of the votes it is entitled to cast in such election in favor of a single candidate and such candidate received no other votes from any other holder of Outstanding Units, or (iv) by any holder of Outstanding Units who is entitled to vote at the meeting, who complied with the notice procedures set forth in paragraphs (c) or (d) of this Section 11.13 and who is a Record Holder of Outstanding Units at the time such notice is delivered to the Secretary of the Company.

(b) For nominations to be properly brought before an annual meeting by a Unitholder pursuant to Section 11.13(a)(iii), the Unitholder must have given timely notice thereof in writing to the Secretary of the Company. To be timely, a Unitholder’s notice shall be delivered to the Secretary at the principal executive offices of the Company not less than 90 or more than 120 days prior to the first anniversary (the “Anniversary”) of the date on which the Company first mailed its proxy materials for the preceding year’s annual meeting of Members; provided, however, that if the date of the annual meeting is advanced more than 30 days prior to or delayed by more than thirty (30) days after the anniversary of the preceding year’s annual meeting, notice by the Unitholder to be timely must be so delivered not later than the close of business on the later of (x) the ninetieth day prior to such annual meeting or (y) the tenth day following the day on which public announcement of the date of such meeting is first made. Such Unitholder’s notice shall set forth: (A) as to each Person whom the Unitholder proposes to nominate for election or reelection as a Director all information relating to such Person that is required to be disclosed in solicitations of proxies for election of Directors, or is otherwise required, in each case pursuant to Regulation 14A under the Exchange Act, including such Person’s written consent to being named in the proxy statement as a nominee and to serving as a Director if elected and (B) as to the Unitholder giving the notice and the beneficial owner, if any, on whose behalf the nomination is made the name and address of such Unitholder, as they appear on the Company’s books, and of such beneficial owner, the class and number of Units of the Company which are owned beneficially and of record by such Unitholder and such beneficial owner. Such holder shall be entitled to nominate as many candidates for election to the Board of Directors as would be elected assuming such holder cast the precise number of votes necessary to elect each candidate and no more votes were cast by such holder or any other holder for such candidates.

(c) For nominations or other business to be properly brought before an annual meeting by a Unitholder pursuant to Section 11.13(a), (i) the Unitholder must have given timely notice thereof in writing to the Secretary of the Company, (ii) such business must be a proper matter for Member action under this Agreement and the Delaware Act, (iii) if the Unitholder, or the beneficial owner on whose behalf any such proposal or nomination is made, has provided the Company with a Solicitation Notice, such Unitholder or beneficial owner must, in the case of a proposal, have delivered a proxy statement and form of proxy to holders of at least the percentage of the Outstanding Units required under this Agreement or Delaware law to carry any such proposal, or, in the case of a nomination or nominations, have delivered a proxy statement and form of proxy to holders of a percentage of the Outstanding Units reasonably believed by such Unitholder or beneficial holder to be sufficient to elect the nominee or nominees proposed to be nominated by such Unitholder, and must, in either case, have included in such materials the Solicitation Notice and (iv) if no Solicitation Notice relating thereto has been timely provided pursuant to this Section 11.13, the Unitholder or beneficial owner proposing such business or nomination

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must not have solicited a number of proxies sufficient to have required the delivery of such a Solicitation Notice. To be timely, a Unitholder’s notice shall be delivered to the Secretary at the principal executive offices of the Company not less than 90 or more than 120 days prior to the first Anniversary; provided, however, that in the event that the date of the annual meeting is advanced more than thirty (30) days prior to or delayed by more than thirty (30) days after the anniversary of the preceding year’s annual meeting, notice by the Unitholder to be timely must be so delivered not later than the close of business on the later of (x) the ninetieth day prior to such annual meeting or (y) the tenth day following the day on which public announcement of the date of such meeting is first made. Such Unitholder’s notice shall set forth: (A) as to each Person whom the Unitholder proposes to nominate for election or reelection as a Director all information relating to such Person that is required to be disclosed in solicitations of proxies for election of Directors, or is otherwise required, in each case pursuant to Regulation 14A under the Exchange Act, including such Person’s written consent to being named in the proxy statement as a nominee and to serving as a Director if elected; (B) as to any other business that the Unitholder proposes to bring before the meeting, a brief description of the business desired to be brought before the meeting, the reasons for conducting such business at the meeting and any material interest in such business of such Unitholder and the beneficial owner, if any, on whose behalf the proposal is made; and (C) as to the Unitholder giving the notice and the beneficial owner, if any, on whose behalf the nomination or proposal is made the name and address of such Unitholder, as they appear on the Company’s books, and of such beneficial owner, the class and number of Units of the Company which are owned beneficially and of record by such Unitholder and such beneficial owner, and whether either such Unitholder or beneficial owner intends to deliver a proxy statement and form of proxy to holders of, in the case of a proposal, at least the percentage of the Outstanding Units required under this Agreement or Delaware law to carry the proposal or, in the case of a nomination or nominations, a sufficient number of holders of the Company’s Outstanding Units to elect such nominee or nominees (an affirmative statement of such intent, a “Solicitation Notice”).

(d) Notwithstanding anything in the second sentence of Section 11.13(b) or the second sentence of Section 11.13(c) to the contrary, if the number of Directors to be elected to the Board of Directors is increased and there is no public announcement naming all of the nominees for Director or specifying the size of the increased Board of Directors made by the Company at least 90 days prior to the Anniversary, then a Unitholder’s notice required by this Section 11.13 shall also be considered timely, but only with respect to nominees for any new positions created by such increase, if it shall be delivered to the Secretary at the principal executive offices of the Company not later than the close of business on the tenth day following the day on which such public announcement is first made by the Company.

(e) Only such business shall be conducted at a special meeting of Members as shall have been brought before the meeting pursuant to the Company’s notice of meeting pursuant to Section 11.4 of this Agreement. Subject to Section 7.1(d), nominations of Persons for election to the Board of Directors may be made at a special meeting of Members at which Directors are to be elected (i) pursuant to the Company’s notice of meeting, (ii) by or at the direction of the Board of Directors, (iii) by any holder of Outstanding Units who is entitled to vote at the meeting, who complied with the notice procedures set forth in paragraph (b) or (d) of this Section 11.13 and who was a Record Holder of a sufficient number of Outstanding Units as of the Record Date for such meeting to elect one or more members to the Board of Directors assuming that such holder cast all of the votes it is entitled to cast in such election in favor of a single candidate and such candidate received no other votes from any other holder of Outstanding Units, or (iv) by any holder of Outstanding Units who is entitled to vote at the meeting, who complies with the notice procedures set forth in this Section 11.13 and who is a Record Holder of Outstanding Units at the time such notice is delivered to the Secretary of the Company. Nominations by Unitholders of Persons for election to the Board of Directors may be made at such a special meeting of Members if the Unitholder’s notice as required by Section 11.13(b) or Section 11.13(c) shall be delivered to the Secretary of the Company not earlier than the ninetieth day prior to such special meeting and not later than the close of business on the later of the seventieth day prior to such special meeting or the tenth day following the day

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on which public announcement is first made of the date of the special meeting and of the nominees proposed by the Board of Directors to be elected at such meeting. Holders of Outstanding Units making nominations pursuant to Section 11.13(e)(iii) shall be entitled to nominate the number of candidates for election at such special meeting as provided in Section 11.13(b) for an annual meeting.

(f) Except to the extent otherwise provided in Section 7.1(d) with respect to vacancies, only Persons who are nominated in accordance with the procedures set forth in this Section 11.13 shall be eligible to serve as Directors and only such business shall be conducted at a meeting of Members as shall have been brought before the meeting in accordance with the procedures set forth in this Section 11.13. Except as otherwise provided herein or required by law, the chairman of the meeting shall have the power and duty to determine whether a nomination or any business proposed to be brought before the meeting was made in accordance with the procedures set forth in this Section 11.13 and, if any proposed nomination or business is not in compliance with this Section 11.13, to declare that such defective proposal or nomination shall be disregarded.

(g) Notwithstanding the foregoing provisions of this Section 11.13, a Member shall also comply with all applicable requirements of the Exchange Act and the rules and regulations thereunder with respect to the matters set forth in this Section 11.13. Nothing in this Section 11.13 shall be deemed to affect any rights of Members to request inclusion of proposals in the Company’s proxy statement pursuant to Rule 14a-8 under the Exchange Act.

ARTICLE XII

MERGER, CONSOLIDATION OR CONVERSION

Section 12.1 Authority. The Company may merge or consolidate with one or more limited liability companies or “other business entities” as defined in Section 18-209 of the Delaware Act, or convert into any “other entity” as defined in Section 18-214 of the Delaware Act, whether such entity is formed under the laws of the State of Delaware or any other state of the United States of America, pursuant to a written agreement of merger or consolidation (“Merger Agreement”) or a written plan of conversion (“Plan of Conversion”), as the case may be, in accordance with this Article XII.

Section 12.2 Procedure for Merger, Consolidation or Conversion.

(a) Merger, consolidation or conversion of the Company pursuant to this Article XII requires the prior approval of the Board of Directors; provided, however, that, to the fullest extent permitted by law, the Board of Directors shall have no duty or obligation to consent to any merger, consolidation or conversion of the Company and may decline to do so free of any fiduciary duty or obligation whatsoever to the Company and any Member and, in declining to consent to a merger, consolidation or conversion, shall not be required to act in good faith or pursuant to any other standard imposed by this Agreement, any other agreement contemplated hereby or under the Delaware Act or any other law, rule or regulation or at equity.

(b) If the Board of Directors shall determine to consent to the merger or consolidation, the Board of Directors shall approve the Merger Agreement, which shall set forth:

(i) the names and jurisdictions of formation or organization of each of the business entities proposing to merge or consolidate;

(ii) the name and jurisdiction of formation or organization of the business entity that is to survive the proposed merger or consolidation (the “Surviving Business Entity”);

(iii) the terms and conditions of the proposed merger or consolidation;

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(iv) the manner and basis of exchanging or converting the rights or obligations of, or securities of, or interests in, each constituent business entity for, or into, cash, property, rights, or securities of or interests in, the Surviving Business Entity; and (A) if any rights or obligations of, or securities of, or interests in, any constituent business entity are not to be exchanged or converted solely for, or into, cash, property, rights or obligations of, securities of or interests in, the Surviving Business Entity, the cash, property, rights, or securities of or interests in, any limited liability company or other business entity which the holders of such rights, securities or interests are to receive in exchange for, or upon conversion of their interests, securities or rights, and (B) in the case of securities represented by certificates, upon the surrender of such certificates, which cash, property, rights or obligations of securities of or interests in the Surviving Business Entity or any other business entity (other than the Surviving Business Entity), or evidences thereof, are to be delivered;

(v) a statement of any changes in the constituent documents or the adoption of new constituent documents (the certificate of formation or limited liability company agreement, articles or certificate of incorporation, articles of trust, declaration of trust, certificate or agreement of limited partnership or other similar charter or governing document) of the Surviving Business Entity to be effected by such merger or consolidation;

(vi) the effective time of the merger or consolidation, which may be the date of the filing of the certificate of merger pursuant to Section 12.4 or a later date specified in or determinable in accordance with the Merger Agreement (provided, that if the effective time of the merger or consolidation is to be later than the date of the filing of the certificate of merger, the effective time shall be fixed no later than the time of the filing of the certificate of merger and stated therein); and

(vii) such other provisions with respect to the proposed merger or consolidation that the Board of Directors determines to be necessary or appropriate.

(c) If the Board of Directors shall determine to consent to the conversion, the Board of Directors shall approve the Plan of Conversion, which shall set forth:

(i) the name of the converting entity and the converted entity;

(ii) a statement that the Company is continuing its existence in the organizational form of the converted entity;

(iii) a statement as to the type of entity that the converted entity is to be and the state or country under the laws of which the converted entity is to be incorporated, formed or organized;

(iv) the manner and basis of exchanging or converting the equity securities of each constituent business entity for, or into, cash, property or interests, rights, securities or obligations of the converted entity;

(v) in an attachment or exhibit, the certificate of formation of the Company; and

(vi) in an attachment or exhibit, the certificate of limited partnership, articles of incorporation, or other organizational documents of the converted entity;

(vii) the effective time of the conversion, which may be the date of the filing of the certificate of conversion or a later date specified in or determinable in accordance with the Plan of Conversion (provided, that if the effective time of the conversion is to be later than the date of the filing of such certificate of conversion, the effective time shall be fixed at a date or time certain at or prior to the time of the filing of such certificate of conversion and stated therein); and

(viii) such other provisions with respect to the proposed conversion that the Board of Directors determines to be necessary or appropriate.

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Section 12.3 Approval by Members of Merger, Consolidation or Conversion.

(a) Except as provided in Section 12.3(d), the Board of Directors, upon its approval of the Merger Agreement or Plan of Conversion, as the case may be, shall direct that the Merger Agreement or Plan of Conversion, as applicable, be submitted to a vote of Members, whether at an annual meeting or a special meeting, in either case in accordance with the requirements of Article XI. A copy or a summary of the Merger Agreement or Plan of Conversion, as applicable, shall be included in or enclosed with the notice of meeting.

(b) Except as provided in Section 12.3(d), the Merger Agreement or Plan of Conversion shall be approved upon receiving the affirmative vote or consent of the holders of a Unit Majority unless the Merger Agreement or Plan of Conversion, as the case may be, contains any provision that, if contained in an amendment to this Agreement, the provisions of this Agreement or the Delaware Act would require for its approval the vote or consent of a greater percentage of the Outstanding Units or of any class of Members, in which case such greater percentage vote or consent shall be required for approval of the Merger Agreement or Plan of Conversion.

(c) Except as provided in Section 12.3(d), after such approval by vote of the Members, and at any time prior to the filing of the certificate of merger or certificate of conversion pursuant to Section 12.4, the merger, consolidation or conversion may be abandoned pursuant to provisions therefor, if any, set forth in the Merger Agreement or Plan of Conversion.

(d) Notwithstanding anything else contained in this Article XII or in this Agreement, the Board of Directors is permitted without Member approval, to convert the Company or any Group Member into a new limited liability entity, to merge the Company or any Group Member into, or convey all of the Company’s assets to, another limited liability entity which shall be newly formed and shall have no assets, liabilities or operations at the time of such conversion, merger or conveyance other than those it receives from the Company or other Group Member if (i) the Board of Directors has received an Opinion of Counsel that the conversion, merger or conveyance, as the case may be, would not result in the loss of the limited liability of any Member or any Group Member or cause the Company or any Group Member to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for federal income tax purposes (to the extent not previously treated as such), (ii) the sole purpose of such conversion, merger or conveyance is to effect a mere change in the legal form of the Company into another limited liability entity and (iii) the governing instruments of the new entity provide the Members and the Board of Directors with the same rights and obligations as are herein contained.

(e) Additionally, notwithstanding anything else contained in this Article XII or in this Agreement, the Board of Directors is permitted without Member approval to merge or consolidate the Company with or into another entity if (A) the Board of Directors has received an Opinion of Counsel that the merger or consolidation, as the case may be, would not result in the loss of the limited liability of any Member under Delaware law or cause the Company to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for federal income tax purposes (to the extent not previously treated as such), (B) the merger or consolidation would not result in an amendment to this Agreement other than any amendments that could be adopted pursuant to Section 11.1(c), (C) the Company is the Surviving Business Entity in such merger or consolidation, (D) each Member Interest outstanding immediately prior to the effective date of the merger or consolidation is to be an identical Member Interest of the Company after the effective date of the merger or consolidation, and (E) the number of Company Securities to be issued by the Company in such merger or consolidation do not exceed 20% of the Company Securities Outstanding immediately prior to the effective date of such merger or consolidation.

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(f) Members are not entitled to dissenters’ rights of appraisal in the event of a merger, consolidation or conversion pursuant to Section 12.1, a sale of all or substantially all of the assets of the Company or the Company’s Subsidiaries, or any other transaction or event.

Section 12.4 Certificate of Merger; Certificate of Conversion. Upon the required approval by the Board of Directors and the Unitholders of a Merger Agreement or Plan of Conversion, a certificate of merger or certificate of conversion, as applicable, shall be executed and filed with the Secretary of State of the State of Delaware in conformity with the requirements of the Delaware Act.

Section 12.5 Effect of Merger or Conversion.

(a) At the effective time of the certificate of merger:

(i) all of the rights, privileges and powers of each of the business entities that has merged or consolidated, and all property, real, personal and mixed, and all debts due to any of those business entities shall be vested in the Surviving Business Entity and after the merger or consolidation shall be the property of the Surviving Business Entity and all other things and causes of action belonging to each of those business entities, shall be vested in the Surviving Business Entity to the extent they were of each constituent business entity;

(ii) the title to any real property vested by deed or otherwise in any of those constituent business entities shall not revert and is not in any way impaired because of the merger or consolidation;

(iii) all rights of creditors and all liens on or security interests in property of any of those constituent business entities shall be preserved unimpaired; and

(iv) all debts, liabilities and duties of those constituent business entities shall attach to the Surviving Business Entity and may be enforced against it to the same extent as if the debts, liabilities and duties had been incurred or contracted by it.

(b) At the effective time of the certificate of conversion:

(i) the other entity or business form shall be deemed to be the same entity as the Company and the conversion shall constitute a continuation of the existence of the Company in the form of such other entity or business form;

(ii) such conversion shall not be deemed to affect any obligations or liabilities of the Company incurred prior to such conversion or the personal liability of any person incurred prior to such conversion, nor shall it be deemed to affect the choice of law applicable to the Company with respect to matters arising prior to such conversion;

(iii) the other entity or business form shall, for all purposes of the laws of the State of Delaware, be deemed to be the same entity as the Company;

(iv) all of the rights, privileges and powers of the Company that has converted, and all property, real, personal and mixed, and all debts due to the Company, as well as all other things and causes of action belonging to the Company, shall remain vested in the other entity or business form to which the Company has converted and shall be the property of such other entity or business form, and the title to any real property vested by deed or otherwise in the Company shall not revert or be in any way impaired;

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(v) all rights of creditors and all liens upon any property of the Company shall be preserved unimpaired, and all debts, liabilities and duties of the Company shall remain attached to the other entity or business form to which the Company has converted, and may be enforced against it to the same extent as if said debts, liabilities and duties had originally been incurred or contracted by it in its capacity as such other entity or business form;

(vi) the rights, privileges, powers and interests in property of the Company, as well as the debts, liabilities and duties of the Company, shall not be deemed, as a consequence of the conversion, to have been transferred to the other entity or business form to the Company has converted for any purpose of the laws of the State of Delaware; and

(vii) the Company Securities that are to be exchanged for or converted into cash, property, rights or securities of or interests in the entity or business form into which the Company is being converted shall be so exchanged or converted in accordance with the Plan of Conversion, or, in addition to or in lieu thereof, if the Plan of Conversion so provides, the Company Securities may be exchanged for or converted into cash, property, rights or securities of or interests in another entity or business form or may be cancelled.

(c) A merger or consolidation effected pursuant to this Article XII shall not be deemed to result in a transfer or assignment of assets or liabilities from one entity to another.

Section 12.6 Business Combination Limitations. Notwithstanding any other provision of this Agreement, with respect to any “Business Combination” (as such term is defined in Section 203 of the DGCL), the provisions of Section 203 of the DGCL shall be applied with respect to the Company as though the Company were a Delaware corporation.

ARTICLE XIII

RIGHT TO ACQUIRE MEMBER INTERESTS

Section 13.1 Right to Acquire Member Interests.

(a) Notwithstanding any other provision of this Agreement, if at any time any Person holds more than 90% of the total Member Interests of any class then Outstanding, such Person shall then have the right, which right it may assign and transfer in whole or in part to the Company or any of its Affiliates, exercisable at its option, to purchase all, but not less than all, of such Member Interests of such class then Outstanding held by other holders, at the greater of (x) the Current Market Price as of the date three days prior to the date that the notice described in Section 13.1(b) is mailed and (y) the highest price paid by such Person or any of its Affiliates for any such Interest of such class purchased during the 90-day period preceding the date that the notice described in Section 13.1(b) is mailed. As used in this Agreement, (i) “Current Market Price” as of any date of any class of Member Interests listed or admitted to trading on any National Securities Exchange means the average of the daily Closing Prices (as hereinafter defined) per Member Interest of such class for the 20 consecutive Trading Days (as hereinafter defined) immediately prior to such date; (ii) “Closing Price” for any day means the average of the high bid and low asked prices on such day, or in the case no such sale takes place on such day, the average of the closing bid and asked prices on such day, regular way, in either case as reported in the principal consolidated transaction reporting system for securities listed or admitted for trading on the principal National Securities Exchange on which the units of that class are listed or admitted to trading, or if the units of that class are not listed or admitted for trading on any National Securities Exchange, the last quoted price on that day, or if no quoted price exists, the average of the high bid low asked price on that day in the over-the-counter market, as reported by the Nasdaq National Market or such other system then in use, or, if on any such day such Member Interests of such class are not quoted by any such organization of that type, the average of the closing bid and asked prices on such day as furnished by a professional market maker

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making a market in such Member Interests of such class selected by the Board of Directors, or if on any such day no market maker is making a market in such Interests of such class, the fair value of such Member Interests on such day as determined by the Board of Directors; and (iii) “Trading Day” means a day on which the principal National Securities Exchange on which such Member Interests of any class are listed or admitted to trading is open for the transaction of business or, if Member Interests of a class are not listed or admitted to trading on any National Securities Exchange, a day on which banking institutions in New York City generally are open.

(b) If any Person elects to exercise the right to purchase Member Interests granted pursuant to Section 13.1(a), the Board of Directors shall deliver to the Transfer Agent notice of such election to purchase (the “Notice of Election to Purchase”) and shall cause the Transfer Agent to mail a copy of such Notice of Election to Purchase to the Record Holders of Member Interests of such class (as of a Record Date selected by the Board of Directors) at least 10, but not more than 60, days prior to the Purchase Date. Such Notice of Election to Purchase shall also be published for a period of at least three consecutive days in at least two daily newspapers of general circulation printed in the English language and published in the Borough of Manhattan, New York. The Notice of Election to Purchase shall specify the Purchase Date and the price (determined in accordance with Section 13.1(a)) at which Member Interests will be purchased and state that such Person elects to purchase such Member Interests, upon surrender of Certificates representing such Member Interests in exchange for payment, at such office or offices of the Transfer Agent as the Transfer Agent may specify, or as may be required by any National Securities Exchange on which such Interests are listed or admitted to trading. Any such Notice of Election to Purchase mailed to a Record Holder of Member Interests at his address as reflected in the records of the Transfer Agent shall be conclusively presumed to have been given regardless of whether the owner receives such notice. On or prior to the Purchase Date, the Person exercising the right to purchase hereunder shall deposit with the Transfer Agent cash in an amount sufficient to pay the aggregate purchase price of all of such Member Interests to be purchased in accordance with this Section 13.1. If the Notice of Election to Purchase shall have been duly given as aforesaid at least 10 days prior to the Purchase Date, and if on or prior to the Purchase Date the deposit described in the preceding sentence has been made for the benefit of the holders of Member Interests subject to purchase as provided herein, then from and after the Purchase Date, notwithstanding that any Certificate shall not have been surrendered for purchase, all rights of the holders of such Member Interests (including any rights pursuant to Articles IV, V, VI, and X) shall thereupon cease, except the right to receive the purchase price (determined in accordance with Section 13.1(a)) for Member Interests therefor, without interest, upon surrender to the Transfer Agent of the Certificates representing such Member Interests, and such Member Interests shall thereupon be deemed to be transferred to the Person exercising the right to purchase hereunder on the record books of the Transfer Agent and the Company, and such Person shall be deemed to be the owner of all such Member Interests from and after the Purchase Date and shall have all rights as the owner of such Member Interests (including all rights as owner of such Member Interests pursuant to Articles IV, V, VI and X).

(c) At any time from and after the Purchase Date, a holder of an Outstanding Member Interest subject to purchase as provided in this Section 13.1 may surrender his Certificate evidencing such Member Interest to the Transfer Agent in exchange for payment of the amount described in Section 13.1(a), therefor, without interest thereon.

(d) Upon the exercise by any Person of the right to purchase Member Interests granted pursuant to Section 13.1(a), no Member shall be entitled to dissenters’ rights of appraisal.

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ARTICLE XIV

GENERAL PROVISIONS

Section 14.1 Addresses and Notices. Any notice, demand, request, report or proxy materials required or permitted to be given or made to a Member under this Agreement shall be in writing and shall be deemed given or made when delivered in person or when sent by first class United States mail or by other means of written communication to the Member at the address described below. Any notice, payment or report to be given or made to a Member hereunder shall be deemed conclusively to have been given or made, and the obligation to give such notice or report or to make such payment shall be deemed conclusively to have been fully satisfied, upon sending of such notice, payment or report to the Record Holder of such Company Securities at his address as shown on the records of the Transfer Agent or as otherwise shown on the records of the Company, regardless of any claim of any Person who may have an interest in such Company Securities by reason of any assignment or otherwise. An affidavit or certificate of making of any notice, payment or report in accordance with the provisions of this Section 14.1 executed by the Company, the Transfer Agent or the mailing organization shall be prima facie evidence of the giving or making of such notice, payment or report. If any notice, payment or report addressed to a Record Holder at the address of such Record Holder appearing on the books and records of the Transfer Agent or the Company is returned by the United States Postal Service marked to indicate that the United States Postal Service is unable to deliver it, such notice, payment or report and any subsequent notices, payments and reports shall be deemed to have been duly given or made without further mailing (until such time as such Record Holder or another Person notifies the Transfer Agent or the Company of a change in his address) if they are available for the Member at the principal office of the Company for a period of one year from the date of the giving or making of such notice, payment or report to the other Members. Any notice to the Company shall be deemed given if received by the Secretary at the principal office of the Company designated pursuant to Section 2.3. The Board of Directors and the Officers may rely and shall be protected in relying on any notice or other document from a Member or other Person if believed by it to be genuine.

Section 14.2 Further Action. The parties shall execute and deliver all documents, provide all information and take or refrain from taking action as may be necessary or appropriate to achieve the purposes of this Agreement.

Section 14.3 Binding Effect. This Agreement shall be binding upon and inure to the benefit of the parties hereto and their heirs, executors, administrators, successors, legal representatives and permitted assigns.

Section 14.4 Integration. This Agreement constitutes the entire agreement among the parties hereto pertaining to the subject matter hereof and supersedes all prior agreements and understandings pertaining thereto.

Section 14.5 Creditors. None of the provisions of this Agreement shall be for the benefit of, or shall be enforceable by, any creditor of the Company.

Section 14.6 Waiver. No failure by any party to insist upon the strict performance of any covenant, duty, agreement or condition of this Agreement or to exercise any right or remedy consequent upon a breach thereof shall constitute waiver of any such breach of any other covenant, duty, agreement or condition.

Section 14.7 Counterparts. This Agreement may be executed in counterparts, all of which together shall constitute an agreement binding on all the parties hereto, notwithstanding that all such parties are not signatories to the original or the same counterpart. Each party shall become bound by this Agreement immediately upon affixing its signature hereto or, in the case of a Person acquiring a Unit,

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upon accepting the certificate evidencing such Unit or, if such Unit is not certificated, upon taking title to such Unit

Section 14.8 Applicable Law. This Agreement shall be construed in accordance with and governed by the laws of the State of Delaware without regard to principles of conflict of law.

Section 14.9 Invalidity of Provisions. If any provision of this Agreement is or becomes invalid, illegal or unenforceable in any respect, the validity, legality and enforceability of the remaining provisions contained herein shall not be affected thereby.

Section 14.10 Consent of Members. Each Member hereby expressly consents and agrees that, whenever in this Agreement it is specified that an action may be taken upon the affirmative vote or consent of less than all of the Members, such action may be so taken upon the concurrence of less than all of the Members and each Member shall be bound by the results of such action.

Remainder of page intentionally left blank.

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IN WITNESS WHEREOF, the parties hereto have executed this Agreement as of the date first written above.


	Majeed S. Nami

	MAJEED S. NAMI IRREVOCABLE TRUST
	DATED 11. JANUARY 2007

	By:	Ariana Nami
	Title:	Trustee

	MAJEED S. NAMI PERSONAL ENDOWMENT
	FUND DATED 11. JANUARY 2007

	By:	Ariana Nami
	Title:	Trustee

	NAMI CAPITAL PARTNERS, LLC

	By:	Majeed S. Nami
	Title:	Manager

	Scott W. Smith

	Richard A. Robert

	Britt Pence

	Patty Avila-Eady

Signature Page to Amended and Restated
Limited Liability Company Agreement

LEHMAN BROTHERS MLP OPPORTUNITY FUND L.P.
By:		Lehman Brothers MLP Opportunity Associates L.P., its general partner
By:		Lehman Brothers MLP Opportunity Associates L.L.C., its general partner
By:
	Name:
	Title:

Signature Page to Amended and Restated
Limited Liability Company Agreement

THIRD POINT PARTNERS LP
By:		Third Point LLC, its investment manager
By:
	Name:
	Title:
THIRD POINT PARTNERS QUALIFIED LP
By:		Third Point LLC, its investment manager
By:
	Name:
	Title:

Signature Page to Amended and Restated
Limited Liability Company Agreement

BLRTQS PARTNERS
By:
	Name:	Todd Q. Swanson
	Title:	Partner
By:
	Name:	Bradley L. Radoff
	Title:	Partner

Signature Page to Amended and Restated
Limited Liability Company Agreement

EXHIBIT A
to the Second Amended and
Restated Agreement of Limited Liability Company of
Vanguard Natural Resources, LLC

Certificate Evidencing Common Units
Representing Member Interests in
Vanguard Natural Resources, LLC

No. [ ] [ ] Common Units

In accordance with Section 4.1 of the Second Amended and Restated Limited Liability Company Agreement of Vanguard Natural Resources, LLC, as amended, supplemented or restated from time to time (the “Company Agreement”), Vanguard Natural Resources, LLC, a Delaware limited liability company (the “Company”), hereby certifies that [ ] (the “Holder”) is the registered owner of Common Units representing Member Interests in the Company (the “Units”) transferable on the books of the Company, in person or by duly authorized attorney, upon surrender of this Certificate properly endorsed. The rights, preferences and limitations of the Common Units are set forth in, and this Certificate and the Units represented hereby are issued and shall in all respects be subject to the terms and provisions of, the Company Agreement. Copies of the Company Agreement are on file at, and will be furnished without charge on delivery of written request to the Company at, the principal office of the Company located at 7700 San Felipe, Suite 485, Houston, Texas 77063, or such other address as may be specified by notice under the Company Agreement. Capitalized terms used herein but not defined shall have the meanings given them in the Company Agreement.

The Holder, by accepting this Certificate, is deemed to have (i) requested admission as, and agreed to become, a Member and to have agreed to comply with and be bound by and to have executed the Company Agreement, (ii) represented and warranted that the Holder has all right, power and authority and, if an individual, the capacity necessary to enter into the Company Agreement, (iii) granted the powers of attorney provided for in the Company Agreement and (iv) made the waivers and given the consents and approvals contained in the Company Agreement.

This certificate shall by governed by, and construed in accordance with, the laws of the State of Delaware, without regard to principles of conflict of laws thereof.

THE HOLDER OF THIS SECURITY ACKNOWLEDGES FOR THE BENEFIT OF VANGUARD NATURAL RESOURCES, LLC THAT THIS SECURITY MAY NOT BE SOLD, OFFERED, RESOLD, PLEDGED OR OTHERWISE TRANSFERRED IF SUCH TRANSFER WOULD (A) VIOLATE THE THEN APPLICABLE FEDERAL OR STATE SECURITIES LAWS OR RULES AND REGULATIONS OF THE SECURITIES AND EXCHANGE COMMISSION, ANY STATE SECURITIES COMMISSION OR ANY OTHER GOVERNMENTAL AUTHORITY WITH JURISDICTION OVER SUCH TRANSFER, (B) TERMINATE THE EXISTENCE OR QUALIFICATION OF VANGUARD NATURAL RESOURCES, LLC UNDER THE LAWS OF THE STATE OF DELAWARE, (C) CAUSE VANGUARD NATURAL RESOURCES, LLC TO BE TREATED AS AN ASSOCIATION TAXABLE AS A CORPORATION OR OTHERWISE TO BE TAXED AS AN ENTITY FOR FEDERAL INCOME TAX PURPOSES (TO THE EXTENT NOT ALREADY SO TREATED OR TAXED) OR (D) VIOLATE THE TERMS AND CONDITIONS OF THE SECOND AMENDED AND RESTATED LIMITED LIABILITY COMPANY AGREEMENT OF VANGUARD NATURAL RESOURCES, LLC, DATED [SEPTEMBER [•]], 2007, AS THE SAME MAY BE AMENDED FROM TIME TO TIME. VANGUARD NATURAL RESOURCES, LLC MAY IMPOSE ADDITIONAL RESTRICTIONS ON THE TRANSFER OF THIS SECURITY IF IT RECEIVES AN OPINION OF COUNSEL THAT SUCH

Exhibit A-1

RESTRICTIONS ARE NECESSARY TO AVOID A SIGNIFICANT RISK OF VANGUARD NATURAL RESOURCES, LLC BECOMING TAXABLE AS A CORPORATION OR OTHERWISE BECOMING TAXABLE AS AN ENTITY FOR FEDERAL INCOME TAX PURPOSES. THE RESTRICTIONS SET FORTH ABOVE SHALL NOT PRECLUDE THE SETTLEMENT OF ANY TRANSACTIONS INVOLVING THIS SECURITY ENTERED INTO THROUGH THE FACILITIES OF ANY NATIONAL SECURITIES EXCHANGE ON WHICH THIS SECURITY IS LISTED OR ADMITTED TO TRADING.

This Certificate shall not be valid for any purpose unless it has been countersigned and registered by the Transfer Agent and Registrar.

Dated:
Countersigned and Registered by:

as Transfer Agent and Registrar
				VANGUARD NATURAL RESOURCES, LLC
				By:
				Name:
				Title:

Exhibit A-2

Reverse of Certificate
ABBREVIATIONS

The following abbreviations, when used in the inscription on the face of this Certificate, shall be construed as follows according to applicable laws or regulations:

TEN COM—	as tenants in common	UNIF GIFT/TRANSFERS MIN ACT
TEN ENT—	as tenants by the entireties		Custodian
		(Cust)		(Minor)
JT TEN—	as joint tenants with right of survivorship
	and not as tenants in common	under Uniform Gifts/Transfers to CD Minors
		Act (State)

Additional abbreviations, though not in the above list, may also be used.

Exhibit A-3

ASSIGNMENT OF COMMON UNITS
in
VANGUARD NATURAL RESOURCES, LLC

FOR VALUE RECEIVED,	hereby assigns, conveys, sells and transfers unto

(Please print or typewrite name and address of Assignee)		(Please insert Social Security or other identifying number of Assignee)
Units representing Member Interests evidenced by this Certificate, subject to the Company Agreement, and does hereby irrevocably constitute and appoint as its attorney-in-fact with full power of substitution to transfer the same on the books of Vanguard Natural Resources, LLC.
Date:		NOTE: The signature to any endorsement hereon
		must correspond with the name as written upon the face of this Certificate in every particular, without alteration, enlargement or change.
SIGNATURE(S) MUST BE GUARANTEED BY A
MEMBER FIRM OF THE NATIONAL		(Signature)
ASSOCIATION OF SECURITIES DEALERS, INC. OR BY A COMMERCIAL BANK OR TRUST COMPANY SIGNATURE(S) GUARANTEED
		(Signature)
No transfer of the Common Units evidenced hereby will be registered on the books of the Company, unless the Certificate evidencing the Common Units to be transferred is surrendered for registration of transfer.

Exhibit A-4

APPENDIX B

GLOSSARY OF TERMS

The following are abbreviations and definitions of terms commonly used in the natural gas and oil industry that are used in this prospectus.

Acquisitions. Refers to acquisitions, mergers or exercise of preferential rights of purchase.

Available Cash means, for any quarter prior to liquidation:

(a) the sum of:

(i) all cash and cash equivalents of Vanguard Natural Resources on hand at the end of that quarter; and

(ii) all additional cash and cash equivalents of Vanguard Natural Resources on hand on the date of determination of available cash for that quarter resulting from working capital borrowings made subsequent to the end of the quarter,

(b) less the amount of any cash reserves established by the board of directors to

(i) provide for the proper conduct of the business of Vanguard Natural Resources (including reserves for future capital expenditures including drilling and acquisitions and for anticipated future credit needs),

(ii) comply with applicable law or any loan agreement, security agreement, mortgage, debt instrument or other agreement or obligation to which Vanguard Natural Resources or any of its subsidiaries is a party or by which it is bound or its assets are subject; or

(iii) provide funds for distributions with respect to any one or more of the next four quarters.

Bbl. One stock tank barrel or 42 U.S. gallons liquid volume.

Bcf. Billion cubic feet.

Bcfe. One billion cubic feet equivalent, determined using a ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

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 well. A well drilled within the proved area of a natural gas or oil reservoir to the depth of a stratigraphic horizon known to be productive.

Dry hole or well. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production would exceed production expenses and taxes.

Exploitation. A drilling or other project which may target proven or unproven reserves, but which generally has a lower risk than that associated with exploration projects.

Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.

MBbls. One thousand barrels of crude oil or other liquid hydrocarbons.

MBtu. One thousand British thermal units.

B-1

Mcf. One thousand cubic feet.

Mcfe. One thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

MMBbls. One million barrels of crude oil or other liquid hydrocarbons.

MMcf. One million cubic feet.

MMcfe. One million cubic feet equivalent, determined using a ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

MMcfe/d. One MMcfe per day.

MMBtu. One million British thermal units.

Net acres or net wells. The sum of the fractional working interests owned in gross acres or gross wells, as the case may be.

NYMEX. New York Mercantile Exchange.

Oil. Crude oil, condensate and natural gas liquids.

Productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceeds production expenses and taxes.

Proved developed reserves. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional natural gas and oil 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 are included in “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. Proved natural gas and oil reserves are the estimated quantities of natural gas, natural gas liquids and crude oil 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 on future conditions.

Proved undeveloped drilling location. A site on which a development well can be drilled consistent with spacing rules for purposes of recovering proved undeveloped reserves.

Proved undeveloped reserves or PUDs. 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 are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units are claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Estimates for proved undeveloped reserves are not attributed 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.

Recompletion. The completion for production of an existing wellbore in another formation from that which the well has been previously completed.

Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reserves.

B-2

Standardized measure. The estimated future cash flows from natural gas and oil properties, taking into account all anticipated future costs of production, development and abandonment, and taking into account expected income tax liabilities, discounted to present value using a 10% discount rate. Our Standardized Measure does not include future income tax expenses because our reserves are owned by our subsidiary Vanguard Natural Resources Holdings, LLC, which is not subject to income taxes.

Successful well. A well capable of producing natural gas and/or oil in commercial quantities.

Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas and oil regardless of whether such acreage contains proved reserves.

Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and a share of production.

Workover. Operations on a producing well to restore or increase production.

B-3

Appendix C

CHAIRMAN EMERITUS
CLARENCE M. NETHERLAND

CHAIRMAN & CEO
FREDERIC D. SEWELL

PRESIDENT & COO
C.H. (SCOTT) REES III

EXECUTIVE COMMITTEE

G. LANCE BINDER - DALLAS
DANNY D. SIMMONS - HOUSTON

P. SCOTT FROST - DALLAS
DAN PAUL SMITH - DALLAS
JOSEPH J. SPELLMAN - DALLAS THOMAS J. TELLA II - DALLAS

August 13, 2007

Mr. Scott W. Smith
Vanguard Natural Resources, LLC
7700 San Felipe, Suite 485
Houston, Texas 77063

Dear Mr. Smith:

In accordance with your request, we have estimated the proved reserves and future revenue, as of March 31, 2007, to the Vanguard Natural Resources, LLC (VNR) interest in certain oil and gas properties located in Kentucky and Tennessee, as listed in the accompanying tabulations. 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 conform to the guidelines of the U.S. Securities and Exchange Commission (SEC).

As presented in the accompanying summary projections, Tables I through IV, we estimate the net reserves and future net revenue to the VNR interest in these properties, as of March 31, 2007, to be:

	Net Reserves		Future Net Revenue ($)
	Oil	Gas		Present Worth
Category	(Barrels)	(MCF)	Total	at 10%
Proved Developed
Producing	175,664	47,462,742	359,493,500		153,191,600
Non-Producing	45,755	1,036,705	9,123,800		3,893,700
Proved Undeveloped	34,923	16,678,665	89,392,600		22,744,700
Total Proved	256,342	65,178,112	458,009,900		179,830,000

The oil reserves shown include condensate only. Oil 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. In accordance with SEC guidelines, 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; the estimates of reserves and future revenue included herein have not been adjusted for risk. Definitions of reserve categories are presented immediately following this letter.

4500 THANKSGIVING TOWER · 1601 ELM STREET · DALLAS, TEXAS 75201-4754 · PH: 214-969-5401 · FAX: 214-969-5411		nsai@nsai-petro.com
1221 LAMAR STREET, SUITE 1200 · HOUSTON, TEXAS 77010-3072 · PH: 713-654-4950 · FAX: 713-654-4951		netherlandsewell.com

C-1

Future gross revenue to the VNR interest is prior to deducting state production taxes. Future net revenue is after deductions for these taxes, future capital costs, and operating expenses but before consideration of federal income taxes. In accordance with SEC guidelines, 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.

The oil price used in this report is based on a March 30, 2007, NYMEX West Texas Intermediate price of $65.87 per barrel and is adjusted for quality, transportation fees, and a regional price differential. Gas prices used in this report are based on a March 30, 2007, NYMEX Henry Hub price of $7.73 per MMBTU and are adjusted by field for energy content, transportation fees, and regional price differentials. All prices are held constant in accordance with SEC guidelines.

Lease and well operating costs used in this report are based on operating expense records of Vinland Energy Eastern, LLC, the operator of the properties. These costs include the per-well overhead expenses allowed under joint operating agreements along with estimates of costs to be incurred at and below the district and field levels. Headquarters general and administrative overhead expenses of VNR are included. Lease and well operating costs are held constant in accordance with SEC guidelines. Capital costs are included as required for workovers, 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 VNR 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 VNR 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. A substantial portion of these reserves are for undeveloped locations. Therefore, these reserves are based on analogy to properties with similar geologic and reservoir characteristics; it may be necessary to revise these estimates as performance data become available. 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.

C-2

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 Vanguard Natural Resources, LLC; Vinland Energy Eastern, LLC; 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.

		Very truly yours,

		NETHERLAND, SEWELL &
		ASSOCIATES, INC.
		By:	/s/ C.H. (SCOTT) REES III, P.E.
			C.H. (Scott) Rees III, P.E.
			President and Chief Operating Officer

By:	/s/ DANNY D. SIMMONS, P.E.	By:	/s/ DAVID E. NICE, P.G.
	Danny D. Simmons, P.E.		David E. Nice, P.G.
	Executive Vice President		Vice President

Date Signed: August 13, 2007		Date Signed: August 13, 2007

DDS: LMP


	Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates Inc. (NSAI) as a convenience to our clients. The digital document is intended to be substantively the same as the original signed document maintained by NSAI. The digital document is subject to the parameters, limitations, and conditions stated in the original document. In the event of any differences between the digital document and the original document, the original document shall control and supersede the digital document.

C-3

5,000,000 Common Units

Representing Limited Liability Company Interests

PROSPECTUS

, 2007

Citi

Lehman Brothers
	A.G. Edwards
		Wachovia Securities
			Jefferies & Company
				BNP PARIBAS

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 NASD filing fee and the NYSE Arca listing fee, the amounts set forth below are estimates.

SEC registration fee	$	4,449
NASD filing fee	14,990
NYSE Arca listing fee	100,000
Printing and engraving expenses	400,000
Accounting fees and expenses	850,000
Legal fees and expenses	1,000,000
Transfer agent and registrar fees	5,000
Miscellaneous	125,561
Total	$	2,500,000

Item 14. Indemnification of Directors and Officers.

The section of the prospectus entitled “The Limited Liability Company Agreement—Indemnification” discloses that we will generally indemnify officers and members of our board of directors to the fullest extent permitted by the law against all losses, claims, damages or similar events and is incorporated herein by this reference. Reference is also made to Section 8 of the Underwriting Agreement to be filed as an exhibit to this registration statement in which we will agree to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act of 1933, as amended, and to contribute 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 limited liability company agreement, Section 18-108 of the Delaware Limited Liability Company Act empowers a Delaware limited liability company to indemnify and hold harmless any member or manager or other persons from and against all claims and demands whatsoever.

To the extent that the indemnification provisions of our limited liability company agreement purport to include indemnification for liabilities arising under the Securities Act of 1933, in the opinion of the SEC, such indemnification is contrary to public policy and is therefore unenforceable.

Item 15. Recent Sales of Unregistered Securities.

In connection with our formation in October 2006, we issued 100% of our common units to Nami for $1000. The offering was exempt from registration under Section 4(2) of the Securities Act because the transaction did not involve a public offering.

II-1

In connection with our private equity offering on April 18, 2007, we issued (i) 240,000 Class B units and 125,000 Class B units to Messrs. Smith and Robert, respectively (ii) 3,250,000 common units, representing a 55.0% interest in us, to Nami and certain of his affiliates in exchange for his interest in Vanguard Natural Gas, LLC (formerly Nami Holding Company, LLC) and (iii) 2,290,000 common units, representing a 38.8% interest in the us, to the Private Investors for $41.2 million. The offering was exempt from registration under Section 4(2) of the Securities Act because the transaction did not involve a public offering. The following table summarizes the offering.

				Percentage Sharing
				Ratio Represented by
				membership Interests
Purchaser	Purchase Price			Purchased
Scott W. Smith		$	—		4.1	%
Richard A. Robert		—			2.1
Lehman Brothers MLP Partners, L.P.		20,610,000			19.4
Third Point Partners LP		10,016,460			9.4
Third Point Partners Qualified LP		8,532,540			8.0
BLRTQS Partners		2,061,000			2.0
Nami Capital Partners, LLC		—			19.8
Majeed S. Nami Personal Endowment		—			16.4
Majeed S. Nami Irrevocable Trust		—			18.8

Item 16. Exhibits and Financial Statement Schedules.

(a) EXHIBIT INDEX

Exhibit Number		Description
1.1**	—	Form of Underwriting Agreement
3.1*	—	Certificate of Formation of Vanguard Natural Resources, LLC
3.2	—	Form of Second Amended and Restated Limited Liability Company Agreement of Vanguard Natural Resources, LLC (included as Appendix A to the Prospectus and including specimen unit certificate for the units)
5.1	—	Opinion of Vinson & Elkins L.L.P. as to the legality of the securities being registered
8.1	—	Opinion of Vinson & Elkins L.L.P relating to tax matters
10.1*	—	Credit Agreement, dated January 3, 2007, by and between Nami Holding Company, LLC, Citibank, N.A., as administrative agent and L/C issuer and the lenders party thereto
10.2*	—	First Amendment to Credit Agreement, dated March 2, 2007, by and between Nami Holding Company, LLC, Citibank, N.A., as administrative agent and L/C issuer, and the lenders party thereto
10.3*	—	Second Amendment to Credit Agreement, dated April 13, 2007, by and between Vanguard Natural Gas, LLC (formerly Nami Holding Company, LLC), Citibank, N.A., as administrative agent and L/C issuer, and the lenders party thereto
10.4*	—	Form of Vanguard Natural Resources, LLC Long-Term Incentive Plan
10.5*	—	Form of Vanguard Natural Resources, LLC Long-Term Incentive Plan Phantom Options Grant Agreement
10.6*	—	Form of Vanguard Natural Resources, LLC Class B Unit Plan
10.7*	—	Form of Vanguard Natural Resources, LLC Class B Unit Plan Restricted Class B Unit Grant
10.8*	—	Management Services Agreement by and between Vinland Energy Operations, LLC, Vanguard Natural Gas, LLC, Trust Energy Company, LLC and Ariana Energy, LLC
10.9*	—	Participation Agreement by and between Vinland Energy Eastern, LLC, Vanguard Natural Gas, LLC, Trust Energy Company, LLC and Ariana Energy, LLC

II-2

10.10*	—	Gathering and Compression Agreement by and between Vinland Energy Gathering, LLC, Vinland Energy Eastern, LLC, Vanguard Natural Gas, LLC and Ariana Energy, LLC
10.11*	—	Gathering and Compression Agreement by and between Vinland Energy Gathering, LLC, Vinland Energy Eastern, LLC, Vanguard Natural Gas, LLC and Trust Energy Company
10.12*	—	Gathering and Compression Agreement by and between Vinland Energy Gathering, LLC and Nami Resources Company, L.L.C.
10.13*	—	Well Services Agreement by and between Vinland Energy Operations, LLC, Vanguard Natural Gas, LLC and Ariana Energy, LLC
10.14*	—	Well Services Agreement by and between Vinland Energy Operations, LLC, Vanguard Natural Gas, LLC and Trust Energy Company, LLC
10.15*	—	Well Services Agreement by and between Vinland Energy Operations, LLC and Nami Resources Company, L.L.C.
10.16*	—	Operating Agreement by and between Vinland Energy Operations, LLC, Vinland Energy Eastern, LLC and Ariana Energy, LLC
10.17*	—	Operating Agreement by and between Vinland Energy Operations, LLC, Vinland Energy Eastern, LLC and Trust Energy Company, LLC
10.18	—	Amended and Restated Indemnity Agreement by and between Nami Resources Company, L.L.C., Vinland Energy Eastern, LLC, Trust Energy Company, LLC, Vanguard Natural Gas, LLC and Vanguard Natural Resources, LLC
10.19*	—	Revenue Payment Agreement by and between Nami Resources Company, L.L.C. and Trust Energy Company
10.20*	—	Gas Supply Agreement by and between Nami Resources Company, L.L.C. and Trust Energy Company
10.21*	—	Amended Employment Agreement, dated April 18, 2007, by and between Scott W. Smith, VNR Holdings, LLC and Vanguard Natural Resources, LLC
10.22*	—	Amended Employment Agreement, dated April 18, 2007, by and between Richard A. Robert, VNR Holdings, LLC and Vanguard Natural Resources, LLC
10.23*	—	Registration Rights Agreement, dated April 18, 2007, between Vanguard Natural Resources, LLC and the private investors named therein
10.24*	—	Purchase Agreement, dated April 18, 2007, between Vanguard Natural Resources, LLC, Majeed S. Nami and the private investors named therein
10.25**	—	Form of Omnibus Agreement
10.26*	—	Employment Agreement, dated May 15, 2007, by and between Britt Pence, VNR Holdings, LLC and Vanguard Natural Resources, LLC
10.27*		Contract for Sale and Purchase of Natural Gas, dated March 6, 2007, between Trust Energy Company, LLC and North American Energy Corporation
10.28*	—	Natural Gas Contract, dated May 26, 2003, between Nami Resources Company, Inc. and Osram Sylvania Products, Inc.
10.29*	—	Natural Gas Purchase Contract, dated December 16, 2004, between Nami Resources Company, LLC and Dominion Field Services, Inc.
10.30*	—	Natural Gas Purchase Contract, dated December 28, 2004, between Nami Resources Company, LLC and Dominion Field Services, Inc.
10.31	—	Director Compensation Agreement
21.1	—	List of subsidiaries of Vanguard Natural Resources, LLC
23.1	—	Consent of UHY LLP
23.2	—	Consent of Rodefer Moss & Co., PLLC
23.3	—	Consent of Vinson & Elkins L.L.P. (included in Exhibit 5.1)
23.4	—	Consent of Vinson & Elkins L.L.P. (included in Exhibit 8.1)
23.5	—	Consent of Netherland Sewell & Associates, Inc.

II-3

23.6	—	Consent of Wright & Company
23.7	—	Consent of Schlumberger Data and Consulting Services
23.8	—	Consent of UHY LLP
24.1*	—	Powers of Attorney (contained on the signature page)
99.1	—	Consent of W. Richard Anderson

* Previously filed

** To be filed by amendment

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 foregoing provisions, 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 of 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 common unitholder, at least on an annual basis, a detailed statement of any transactions with Vinland or its subsidiaries, and of fees, commissions, compensation and other benefits paid, or accrued to Vinland or its subsidiaries 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 common unitholders the financial statements required by Form 10-K for the first full fiscal year of operations of the company.

II-4

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 September 18, 2007.

	VANGUARD NATURAL RESOURCES, LLC
	By:	/s/ SCOTT W. SMITH
		Scott W. Smith
		President and Chief Executive Officer

Pursuant to the requirements of the Securities Act of 1933, as amended, this Registration Statement has been signed below by the following persons in the capacities and on the dates indicated.

	Name		Title		Date
/s/ SCOTT W. SMITH		President and Chief Executive		September 18, 2007
Scott W. Smith		Officer (Principal Executive Officer)
/s/ RICHARD A. ROBERT		Executive Vice President and		September 18, 2007
Richard A. Robert		Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer)
*		Director		September 18, 2007
Lasse Wagene
*		Director		September 18, 2007
Thomas M. Blake
		Director		September 18, 2007
Michael J. Cannon
* By: /s/ SCOTT W. SMITH				September 18, 2007
Attorney-in-fact

II-5

EXHIBIT INDEX

(a) EXHIBIT INDEX

Exhibit Number		Description
1.1**	—	Form of Underwriting Agreement
3.1*	—	Certificate of Formation of Vanguard Natural Resources, LLC
3.2	—	Form of Second Amended and Restated Limited Liability Company Agreement of Vanguard Natural Resources, LLC (included as Appendix A to the Prospectus and including specimen unit certificate for the units)
5.1	—	Opinion of Vinson & Elkins L.L.P. as to the legality of the securities being registered
8.1	—	Opinion of Vinson & Elkins L.L.P relating to tax matters
10.1*	—	Credit Agreement, dated January 3, 2007, by and between Nami Holding Company, LLC, Citibank, N.A., as administrative agent and L/C issuer and the lenders party thereto
10.2*	—	First Amendment to Credit Agreement, dated March 2, 2007, by and between Nami Holding Company, LLC, Citibank, N.A., as administrative agent and L/C issuer, and the lenders party thereto
10.3*	—	Second Amendment to Credit Agreement, dated April 13, 2007, by and between Vanguard Natural Gas, LLC (formerly Nami Holding Company, LLC), Citibank, N.A., as administrative agent and L/C issuer, and the lenders party thereto
10.4*	—	Form of Vanguard Natural Resources, LLC Long-Term Incentive Plan
10.5*	—	Form of Vanguard Natural Resources, LLC Long-Term Incentive Plan Phantom Options Grant Agreement
10.6*	—	Form of Vanguard Natural Resources, LLC Class B Unit Plan
10.7*	—	Form of Vanguard Natural Resources, LLC Class B Unit Plan Restricted Class B Unit Grant
10.8*	—	Management Services Agreement by and between Vinland Energy Operations, LLC, Vanguard Natural Gas, LLC, Trust Energy Company, LLC and Ariana Energy, LLC
10.9*	—	Participation Agreement by and between Vinland Energy Eastern, LLC, Vanguard Natural Gas, LLC, Trust Energy Company, LLC and Ariana Energy, LLC
10.10*	—	Gathering and Compression Agreement by and between Vinland Energy Gathering, LLC, Vinland Energy Eastern, LLC, Vanguard Natural Gas, LLC and Ariana Energy, LLC
10.11*	—	Gathering and Compression Agreement by and between Vinland Energy Gathering, LLC, Vinland Energy Eastern, LLC, Vanguard Natural Gas, LLC and Trust Energy Company
10.12*	—	Gathering and Compression Agreement by and between Vinland Energy Gathering, LLC and Nami Resources Company, L.L.C.
10.13*	—	Well Services Agreement by and between Vinland Energy Operations, LLC, Vanguard Natural Gas, LLC and Ariana Energy, LLC
10.14*	—	Well Services Agreement by and between Vinland Energy Operations, LLC, Vanguard Natural Gas, LLC and Trust Energy Company, LLC
10.15*	—	Well Services Agreement by and between Vinland Energy Operations, LLC and Nami Resources Company, L.L.C.
10.16*	—	Operating Agreement by and between Vinland Energy Operations, LLC, Vinland Energy Eastern, LLC and Ariana Energy, LLC
10.17*	—	Operating Agreement by and between Vinland Energy Operations, LLC, Vinland Energy Eastern, LLC, Trust Energy Company, LLC, Vanguard Natural Gas, LLC and Vanguard Natural Resources, LLC
10.18	—	Amended and Restated Indemnity Agreement by and between Nami Resources Company, L.L.C., Vinland Energy Eastern, LLC and Trust Energy Company, LLC

II-6

10.19*	—	Revenue Payment Agreement by and between Nami Resources Company, L.L.C. and Trust Energy Company
10.20*	—	Gas Supply Agreement by and between Nami Resources Company, L.L.C. and Trust Energy Company
10.21*	—	Amended Employment Agreement, dated April 18, 2007, by and between Scott W. Smith, VNR Holdings, LLC and Vanguard Natural Resources, LLC
10.22*	—	Amended Employment Agreement, dated April 18, 2007, by and between Richard A. Robert, VNR Holdings, LLC and Vanguard Natural Resources, LLC
10.23*	—	Registration Rights Agreement, dated April 18, 2007, between Vanguard Natural Resources, LLC and the private investors named therein
10.24*	—	Purchase Agreement, dated April 18, 2007, between Vanguard Natural Resources, LLC, Majeed S. Nami and the private investors named therein
10.25**	—	Form of Omnibus Agreement
10.26*	—	Employment Agreement, dated May 15, 2007, by and between Britt Pence, VNR Holdings, LLC and Vanguard Natural Resources, LLC
10.27*		Contract for Sale and Purchase of Natural Gas, dated March 6, 2007, between Trust Energy Company, LLC and North American Energy Corporation
10.28*	—	Natural Gas Contract, dated May 26, 2003, between Nami Resources Company, Inc. and Osram Sylvania Products, Inc.
10.29*	—	Natural Gas Purchase Contract, dated December 16, 2004, between Nami Resources Company, LLC and Dominion Field Services, Inc.
10.30*	—	Natural Gas Purchase Contract, dated December 28, 2004, between Nami Resources Company, LLC and Dominion Field Services, Inc.
10.31	—	Director Compensation Agreement
21.1	—	List of subsidiaries of Vanguard Natural Resources, LLC
23.1	—	Consent of UHY LLP
23.2	—	Consent of Rodefer Moss & Co., PLLC
23.3	—	Consent of Vinson & Elkins L.L.P. (included in Exhibit 5.1)
23.4	—	Consent of Vinson & Elkins L.L.P. (included in Exhibit 8.1)
23.5	—	Consent of Netherland Sewell & Associates, Inc.
23.6	—	Consent of Wright & Company
23.7	—	Consent of Schlumberger Data and Consulting Services
23.8	—	Consent of UHY LLP
24.1*	—	Powers of Attorney (contained on the signature page)
99.1	—	Consent of W. Richard Anderson

* Previously filed

** To be filed by amendment

II-7

Lehman Brothers

A.G. Edwards

Wachovia Securities

Jefferies & Company

BNP PARIBAS