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 $ 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 18 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 December 31, 2006 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 December 31, 2006 is provided in Appendix C and is referred to in this prospectus as the reserve report.

As used in this prospectus, unless we indicate otherwise: (1) “Vanguard Natural Resources, LLC,” “we,” “our,” “us” or like terms when used in a historical context refer to our predecessor and, when used in the present or future tense, 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 100% of Vinland and will own an approximate 27.1% 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 the historical financial information and reserve data of our predecessor described beginning on page 14 of this prospectus as adjusted to give effect to the separation of our operating company and Vinland as described under “Nami Restructuring Plan” below, as well as our recent private placement, new reserve-based credit facility and this offering.

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.

We owned working interests in 845 gross (786 net) productive wells at December 31, 2006 and our average net production for the twelve months ended December 31, 2006 was 11,995 Mcfe per day. We also have a 40% working interest in approximately 107,000 gross undeveloped acres surrounding or adjacent to our existing wells located in southeast Kentucky and northeast Tennessee. Vinland owns the remaining 60% working interest in this acreage, as well as a 100% working interest in depths above and 100 feet below our known producing horizons and is expected to act 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 this 40% working interest. In addition, we own a contract right to receive 100% of the net proceeds from the sale of production from certain oil and gas wells located in Bell and Knox Counties, Kentucky, which accounted for approximately 5% of our pro forma estimated proved reserves as of December 31, 2006. Our estimated pro forma proved reserves at December 31, 2006 were 66.0 Bcfe, of which approximately 97% were natural gas and 75% were classified as proved developed. Our properties, including our 40% working interest in approximately 107,000 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 pro forma proved reserves-to-production ratio, or average reserve life, is approximately 15 years based on our pro forma proved reserves as of December 31, 2006 and our production for the year ended December 31, 2006. During 2006, we drilled 100 gross wells and as of December 31, 2006, we had identified 325 additional proved undeveloped drilling locations and over 155 other drilling locations on our leasehold acreage. Pursuant to a participation agreement that we have entered into with Vinland, Vinland generally has control over our drilling program and the sole right to determine which wells are drilled until January 1, 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 a 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 net wells, in which we will own a 100% working interest, in a given quarterly period. Based on our production rate at December 31, 2006, we believe we need to drill approximately 130 gross wells (52 net wells) per year to maintain our production at current levels. If Vinland only drills its minimum commitment of 100 gross wells per calendar year, we believe that our total production and our production will decline by approximately 2% to 3% per year over the next four years, after which our production will increase by approximately 6% in the fifth year. These declines and subsequent increase in our production together result in an approximate overall 4% decline in our production for the next five years. If Vinland drills its minimum commitment during the four year period, 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 for five years 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 in four years, after which we each will have the right to propose the drilling of wells within the AMI and 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.

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 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 Transmission system was $0.25 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.

wells producing at December 31, 2006 at $7.69 per MMBtu. However, as a result of expected production from wells that began or are expected to begin producing after December 31, 2006, our fixed price swaps hedge approximately 60% of our expected production for the twelve month period ending June 30, 2008 at $7.81 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.

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 $115.5 million of borrowing capacity under our reserve-based credit facility, which should allow us to compete effectively for opportunistic acquisitions.

Our Relationship with Vinland

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. As of December 31, 2006, 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 a 60% working interest in approximately 107,000 gross undeveloped acres in the AMI, interests 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 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. 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. 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, as described below, 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 the participation agreement described below, 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. 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. 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 the participation agreement described above that we have entered into with Vinland, Vinland has control over our drilling program and has the sole right to determine which wells are proposed to be drilled. Please read “Certain Relationships and Related Party Transactions.”

Under a management services agreement, Vinland will advise and consult with us regarding all aspects of our production and development operations, and provide 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. Please read “Certain Relationships and Related Party Transactions—Management Services 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. Please read “Conflicts of Interest and Fiduciary Duties.”

Cash Distribution Policy

Our board of directors has adopted a cash distribution policy to pay a regular quarterly distribution of $0.42 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 November 14, 2007 for the period from the closing of this offering through September 30, 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, and we cannot assure you that we will not reduce or eliminate our distributions.

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 cannot assure you of our ability 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 would have been approximately $13.7 million. This amount of pro forma cash available for distribution would have been sufficient to allow us to pay approximately 68% of the initial quarterly distributions on our common units and Class B units during this period (66%, 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 June 30, 2008, 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. Please read carefully the risks under the caption “Risk Factors.”

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 a 60% working interest in approximately 107,000 gross undeveloped acres in the AMI, interests 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 or 100 feet below our known producing horizons and 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 operating company’s proved producing wells and associated reserves along with the remaining 40% working interest in the approximately 107,000 gross undeveloped acres in the AMI as well as a contract right 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 in Bell and Knox Counties, Kentucky, which accounted for approximately 5% of our pro forma estimated proved reserves as of December 31, 2006. In addition, we recently changed the name of our operating company from Nami Holding Company, LLC to Vanguard Natural Gas, LLC.

Private Placement

Reserve-Based Credit Facility

On January 3, 2007, our operating company entered into a reserve-based credit facility under which our initial borrowing base was set at $115.5 million of which $114.6 million was outstanding as of March 31, 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 the $114.6 million of indebtedness outstanding under the 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 460,000 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 27.1% membership interest in us;

· the Private Investors will own 2,290,000 common units, representing an aggregate 19.1% membership interest in us; and

· the public unitholders will own 6,000,000 common units, representing an aggregate 50.0% 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. 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. The remaining Class B units have been reserved for additional management personnel that we intend to hire in the future. 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.

We will use 50% of any net proceeds from the exercise of the underwriters’ option to redeem a number of common units from Nami and the Private Investors, in proportion to their respective ownership positions, equal to 50% of the number of common units issued upon the exercise of the underwriters’ option. If the underwriters’ option to purchase additional common units is exercised in full, Nami’s ownership of common units will be reduced from 3,250,000 common units to 2,986,011 common units, or 24.0% of all then outstanding units, the Private Investors’ ownership of common units will be reduced from 2,290,000 common units to 2,103,989 common units, or 16.9% of all then outstanding units, and the ownership interest of the public unitholders will increase to 6,900,000 common units, or 55.4% of all the outstanding units. The remaining net proceeds, if any, from the exercise of the underwriters’ option to purchase additional common units will be used for working capital and general limited liability company purposes.

Our board of directors has sole responsibility for overseeing our business. 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 ownership of common units will be reduced from 3,250,000 common units to 2,986,011 common units, or 24.0% of all then outstanding units, the Private Investors’ ownership of common units will be reduced from 2,290,000 common units to 2,103,989 common units, or 16.9% of all then outstanding units, management’s membership interest will be reduced to 3.7%, and the ownership interest of the public unitholders will increase to 6,900,000 common units, or 55.4% of all the outstanding units.

(2) Includes 460,000 Class B units, of which 240,000 Class B units have been issued to Scott W. Smith, our President and Chief Executive Officer, and 125,000 Class B units have been issued to Richard A. Robert, our Executive Vice President and Chief Financial Officer. The remaining Class B units have been reserved for additional management personnel that we intend to hire in the future.

The Offering

Units offered by us		6,000,000 common units.
		6,900,000 common units if the underwriters exercise their option to purchase 900,000 additional common units in full.
Units outstanding after this offering		12,000,000 common units; 12,450,000 common units if the underwriters’ exercise their option to purchase additional units in full.
Use of proceeds		We anticipate using the estimated net proceeds of $ million(1) from this offering, after deducting the estimated underwriting discounts and fees of $ million, to:
		· repay $ million of the indebtedness outstanding under our reserve-based credit facility;
		· pay $ million of accrued distributions to Nami, management and the Private Investors under our limited liability company agreement;
		· pay $ million of expenses associated with this offering; and
		· use the remaining amount of $ million to fund future working capital. Please read “Use of Proceeds.”
		(1) Assumes an initial public offering price of $ 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 $ million and structuring fees of $ .

We will use 50% of any net proceeds from the exercise of the underwriters’ option to redeem a number of common units from Nami and the Private Investors, in proportion to their respective ownership positions, equal to 50% of the number of common units issued upon the exercise of the underwriters’ option. We also have an obligation to reimburse Nami and the Private Investors for the underwriters’ discount on the common units redeemed from Nami and the Private Investors, provided, however, that we have no obligation to reimburse Nami and the Private Investors for the portion of any underwriting discounts applicable to an offering price exceeding $21.50. If the underwriters’ option to purchase additional common units is exercised in full, Nami’s ownership of common units will be reduced from 3,250,000 common units to 2,986,011 common units, or 24.0% of all then outstanding units, the Private Investors’ ownership of common units will be reduced from 2,290,000 common units to 2,103,989 common units, or 16.9% of all then outstanding units, management’s membership interest will be reduced to 3.7%, and the ownership interest of the public unitholders will increase to 6,900,000 common units, or 55.4% of all the outstanding units. The remaining net proceeds, if any, from the exercise of the underwriters’ option to purchase additional common units will be used for working capital and general corporate purposes.

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 $0.42 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 September 30, 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 September 30, 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 $0.42 on all units for each quarter through June 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 would have been approximately $13.7 million. This amount of pro forma cash available for distribution would have been sufficient to allow us to pay approximately 68% of the initial quarterly distributions on our units during this period (66%, 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 June 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 elect three additional members to our board of directors. Thus, subsequent to the completion of this offering, our board of directors will consist of five members, all of whom will be subject to election at each annual meeting of holders of outstanding units. 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 % 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		We intend to apply to list our units on the NYSE Arca under the symbol “VNR.”

Summary Historical and Unaudited Pro Forma Consolidated Financial And Operating Data

Set forth below is our summary historical and unaudited pro forma consolidated financial and operating data for the periods indicated for Vanguard Natural Resources, LLC and 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 pro forma as adjusted statement of operations data gives effect to the separation of our predecessor and Vinland, as part of the Nami Restructuring Plan, as well as our recent private placement, new reserve-based credit facility and this offering as if such transactions occurred on January 1, 2006. The pro forma as adjusted balance sheet data gives effect to these transactions as if they occurred on December 31, 2006.

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.”

	Year Ended December 31,						Year Ended December 31, 2006
	2004			2005			Historical			Pro Forma As Adjusted
										(unaudited)
	(in thousands)
Statement of Operations Data:
Revenues:
Natural gas and oil sales	$	23,881		$	40,299		$	38,184			$	38,185
Realized losses on derivative contracts	(5,926		)	(10,024		)	(2,208		)		(2,208)
Change in fair value of derivative contracts(1)	(991		)	(18,779		)	17,748				17,748
Other	29			451			665				—
Total revenues	16,993			11,947			54,389				53,725
Costs and Expenses:
Lease operating expenses	2,407			4,607			4,896				5,068
Depreciation, depletion and amortization	4,029			6,189			8,633				7,927
Selling, general and administrative	3,154			5,946			5,199				3,024
Taxes other than income	611			1,249			1,774				1,731
Total costs and expenses	10,201			17,991			20,502				17,750
Income (Loss) from Operations:	6,792			(6,044		)	33,887				35,975
Other Income and (Expenses):
Interest income	7			52			40				40
Interest and financing expenses	(1,455		)	(4,566		)	(7,372		)		—
Total other income and (expenses)	(1,448		)	(4,514		)	(7,332		)		40
Net income (loss)	$	5,344		$	(10,558	)	$	26,555			$	36,015
Cash Flow Data:
Net cash provided by operating activities(1)	$	9,607		$	10,530		$	16,087			$	—
Net cash used in investing activities	(19,598		)	(37,068		)	(37,383		)		—
Net cash provided by financing activities	12,721			25,571			19,985				—
Other Financial Information (unaudited):
Adjusted EBITDA(2)	$	11,812		$	18,924		$	24,772			$	26,154

	As of December 31,				As of December 31, 2006
	2004		2005		Historical		Pro Forma As Adjusted
							(unaudited)
	(in thousands)
Balance Sheet Data:
Cash and cash equivalents	$	4,009	$	3,041	$	1,731		$	888
Other current assets	10,033		19,598		20,438			7,095
Natural gas and oil properties, net of accumulated depreciation, depletion and amortization	54,761		83,513		104,684			95,350
Property, plant and equipment, net of accumulated depreciation	1,894		4,104		11,873			—
Other assets	—		—		—			5,255
Total assets	$	70,697	$	110,256	$	138,726		$	108,588
Short-term derivative contracts	$	800	$	11,527	$	2,022		$	2,022
Other current liabilities	6,347		12,033		11,505			8,528
Long-term debt	42,318		72,708		94,068			—
Long-term derivative contracts	191		8,243		—			—
Other long-term liabilities	130		212		418			418
Members’ capital	20,911		5,533		30,713			97,620
Total liabilities and members’ capital	$	70,697	$	110,256	$	138,726		$	108,588

(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 historical and pro forma estimated net proved reserves for the periods indicated for our predecessor. 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. A summary prepared by NSAI of its reserve report relating to our properties on a pro forma basis as of December 31, 2006 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.

	Predecessor				Pro Forma
	As of December 31,				As of December 31,
	2006				2006
Reserve Data:
Estimated net proved reserves:
Natural gas (Bcf)		94.2				64.3
Crude oil (MMbls)		343				287
Total (Bcfe)		96.3				66.0
Proved developed (Bcfe)		49.7				49.7
Proved undeveloped (Bcfe)		46.6				16.3
Proved developed reserves as % of total proved reserves		52		%		75		%
Standardized Measure (in millions)(1)		$	148.8			$	120.9
Representative Natural Gas and Oil Prices:
Natural gas—NYMEX Henry Hub per MMBtu		$	5.63			$	5.63
Oil—NYMEX WTI per Bbl		$	57.75			$	57.75

	Year Ended December 31,			Pro forma
	2006			As of December 31, 2006
Net Production:
Total realized production (MMcfe)		4,378			4,378
Average daily production (Mcfe/d)		11,995			11,995
Average Realized Sales Prices ($ per Mcfe):
Average realized sales prices (including hedges)		$	8.22		$	8.22
Average realized sales prices (excluding hedges)		$	8.72		$	8.72
Average Unit Costs ($ per Mcfe):
Production costs(2)		$	1.52		$	1.55
Selling, general and administrative expenses		$	1.19		$	0.69
Depreciation, depletion and amortization		$	1.97		$	1.80

(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.

Non-GAAP Financial Measure

Adjusted EBITDA

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

· Net interest expense;

· Depreciation, depletion and amortization; and

· Change in fair value of derivative contracts.

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:

	Year Ended December 31,					Year Ended December 31, 2006
	2004		2005			Historical			Pro Forma
									(unaudited)
	(in thousands)					(in thousands)
Net income (loss)	$	5,344	$	(10,558	)	$	26,555			$	36,015
Plus:
Interest expense	1,455		4,566			7,372				—
Depreciation, depletion and amortization	4,029		6,189			8,633				7,927
Change in fair value of derivative contracts(1)	991		18,779			(17,748		)		(17,748		)
Less:
Interest income	7		52			40				40
Adjusted EBITDA	$	11,812	$	18,924		$	24,772			$	26,154

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. 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.

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 a participation agreement that we have entered into with Vinland, Vinland generally has control over our drilling program and the sole right to determine which wells are drilled until January 1, 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. 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.

Although we intend to have an ongoing natural gas price hedging strategy, 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, the closing price of a calendar month NYMEX natural gas price ranged from a high of $11.43 per MMBtu to a low of $4.20 per MMBtu. 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 December 31, 2006 reserve report, our average annual decline rate for our pro forma proved developed producing reserves is approximately 8% during the first five years, 5% in the next five years and less than 4% 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 December 31, 2006, we believe we need to drill approximately 130 gross wells (52 net wells) per year to maintain our production at current levels. As of December 31, 2006, we had identified 325 additional proved undeveloped drilling locations and over 155 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 three and a half years.

Vinland controls our drilling program. Vinland has agreed to drill not less than 100 gross wells per calendar year for each of the next four years. If Vinland drills only its minimum commitment, we believe that our total production will decline by approximately 2% to 3% per year over the next four years.

Pursuant to a participation agreement that we have entered into with Vinland, Vinland generally has control over our drilling program and the sole right to determine which wells are drilled until January 1, 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 a 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 net wells, in which we will own a 100% working interest, in a given quarterly period. Based on our production rate at December 31, 2006, we believe we need to drill approximately 130 gross wells (52 net wells) per year to maintain our production at current levels. If Vinland only drills its minimum commitment of 100 gross wells per calendar year, we believe that our total production will decline by approximately 2% to 3% per year over the next four years. 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 for five years 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 in four years. 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. 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.

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 1, 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.

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 $20.2 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 would have been approximately $13.7 million. This amount of pro forma cash available for distribution would have been sufficient to allow us to pay approximately 68% of the initial quarterly distributions on our units during this period (66%, 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 June 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 June 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 June 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, if natural gas prices decline by $1.00 per MMBtu, then the standardized measure of our pro forma proved reserves as of December 31, 2006 would decrease from $120.9 million to $90.7 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.

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 these 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 the availability of those facilities 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, 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.

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 have a material adverse effect on 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. 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.

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 of December 31, 2006, we had identified 325 proved undeveloped drilling locations and over 155 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 155 unproved drilling locations we have identified and scheduled for drilling and therefore there may exist greater uncertainty 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 have a material adverse impact on our business activities, financial condition and results of operations.

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

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. Giving effect to the use of the net proceeds from this offering, we estimate that we will have no 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 swaps, costless collars and NYMEX put options to hedge natural gas prices. We have a costless collar in place for 79% of our expected production from proved producing reserves from February through June of 2007. Our fixed-priced swaps hedge from July 1, 2007 through 2011 approximately 80% of our expected production from wells producing at December 31, 2006 at $7.69 per MMBtu. However, as a result of expected production from wells that began or are expected to begin producing after December 31, 2006, our fixed price swaps hedge approximately 60% of our expected production for the twelve month period ending Junc 30, 2008 at $7.81 per MMBtu. 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 Resource 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 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, which accounted for 5% of our pro forma proved reserves as of December 31, 2006. 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 trade credit risk in the ordinary course of our business activities.

We are exposed to risks of loss in the event of 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. Any increase in the nonpayment or nonperformance by our customers and/or counterparties could reduce our ability to make distributions to our unitholders.

We depend on senior management personnel, each of whom would be difficult to replace.

We depend on the performance of Scott W. Smith, our President and Chief Executive Officer, and Richard A. Robert, our Executive Vice President and Chief Financial Officer. We maintain no key person insurance for either Mr. Smith or Mr. Robert. The loss of either or both of Messrs. Smith and Robert could negatively impact our ability to execute our strategy and our results of operations.

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

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

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 have a material adverse impact on our business activities, financial condition and results of operations.

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 have a material adverse effect on 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 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.

We will incur increased costs as a result of being a public company.

We have no history operating as a public company. As a public company, we will incur significant legal, accounting and other expenses that we did not incur as a private company. In addition, the Sarbanes-Oxley Act of 2002, as well as new rules subsequently implemented by the SEC and NYSE Arca, have required changes in corporate governance practices of public companies. We expect these new rules and regulations to increase our legal and financial compliance costs and to make activities more time-consuming and costly. For example, as a result of becoming a public company, we are required to have three independent directors, create board committees and adopt policies regarding internal controls and disclosure controls and procedures, including the preparation of reports on internal control over financial reporting. In addition, we will incur additional costs associated with our public company reporting requirements. We also expect these new rules and regulations to make it more difficult and more expensive for us to obtain director and officer liability insurance and we may be required to accept reduced policy limits and coverage or incur substantially higher costs to obtain the same or similar coverage. As a result, it may be more difficult for us to attract and retain qualified persons to serve on our board of directors or as executive officers. The costs we incur as a result of being a public company will decrease the amount of cash available to pay distributions to you.

Risks Related to Our Structure

Mr. Nami, who together certain of his affiliates and related persons, will own approximately 27.1% 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, which is 100% owned by Nami. 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, however, 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.

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.

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

The initial public offering price of $ per common unit exceeds our pro forma net tangible book value of $ per common unit. Based on an assumed initial public offering price of $ , you will incur immediate and substantial dilution of $ per common unit. The main factor causing dilution is that Nami 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 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 6,000,000 publicly traded common units (6,900,000 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.

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

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

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. 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.

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 Common 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. 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

We expect to receive net proceeds of $ million from the sale of 6,000,000 common units offered by this prospectus, after deducting the underwriting discounts. Our estimates assume an initial offering price of $ 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 $ million.

We anticipate using the estimated net proceeds of $ million from this offering to:

· repay $ million of the indebtedness outstanding under our reserve-based credit facility;

· pay $ million of accrued distributions to Nami, management and the Private Investors under our limited liability company agreement;

· pay $ million of expenses associated with this offering; and

· use the remaining amount of $ million to fund future working capital. Please read “Use of Proceeds.”

As of March 31, 2007, we had $114.6 million outstanding under our reserve-based credit facility. Our reserve-based credit facility matures on January 3, 2011 and as of March 31, 2007 bore interest at 7.36% per year. 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 puts 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.

We will use 50% of any net proceeds from the exercise of the underwriters’ option to redeem a number of common units from Nami and the Private Investors, in proportion to their respective ownership positions, equal to 50% of the number of common units issued upon the exercise of the underwriters’ option. We also have an obligation to reimburse Nami and the Private Investors for the underwriters’ discount on the common units redeemed from Nami and the Private Investors, provided, however, that we have no obligation to reimburse Nami and the Private Investors for the portion of any underwriting discounts applicable to an offering price exceeding $21.50. If the underwriters’ option to purchase additional common units is exercised in full, Nami’s ownership of common units will be reduced from 3,250,000 common units to 2,986,011 common units, or 24.0% of all then outstanding units, the Private Investors’ ownership of common units will be reduced from 2,290,000 common units to 2,103,989 common units, or 16.9% of all then outstanding units, management’s membership interest will be reduced to 3.7%, and the ownership interest of the public unitholders will increase to 6,900,000 common units, or 55.4% of all the outstanding units. The remaining net proceeds, if any, from the exercise of the underwriters’ option to purchase additional common units will be used for working capital and general corporate purposes.

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 December 31, 2006;

· our pro forma capitalization as of December 31, 2006 to give effect to (i) the conveyance of certain operations from our predecessor to Vinland, (ii) the incurrence of $107.4 million of debt in connection with our entering into our new reserve-based credit facility in January 2007 and the repayment of $94.1 million of borrowings under our prior credit facilities and (iii) to reflect our private equity offering in April 2007;

· our pro forma as adjusted capitalization as of December 31, 2006 to give effect to all of the transactions reflected above in the pro forma capitalization and this offering of common units and the application of the net proceeds, including the repayment of $107.4 million borrowed under our new 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 December 31, 2006
	Historical		Pro Forma				Pro Forma As Adjusted
			(unaudited)				(unaudited)
	(in thousands)
Cash and cash equivalents	$	1,731		$	1,732			$	888
Credit facilities	94,068			—				—
New reserve-based credit facility(1)	—			107,424				—
Members’ equity:
Units held by public(2)	—			—				109,100
Units held by the Private Investors	—			41,220				40,258
Units held by Nami and management(3)	30,713			(50,181		)		(51,739		)
Total capitalization	$	124,781		$	98,463			$	97,619

(1) Includes $107.4 million of borrowings under our new reserve-based credit facility that we entered into in January 2007 to refinance our pre-existing credit facilities and to enter into and terminate certain hedging transactions. As of March 31, 2007 we had approximately $114.6 million outstanding under our reserve-based credit facility.

(2) A 1,000,000 unit increase in the number of common units issued to the public would result in a $18.6 million increase in the public unitholders’ members’ equity and a $18.6 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 and cash equivalents would increase or decrease by $5.6 million.

(3) Includes 460,000 Class B units, of which 240,000 Class B units have been issued to Scott W. Smith, our President and Chief Executive Officer, and 125,000 Class B units have been issued to Richard A. Robert, our Executive Vice President and Chief Financial Officer. The remaining 95,000 Class B units have been reserved for additional management personnel that we intend to hire in the future.

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 $ per common unit, on a pro forma basis as of December 31, 2006, after giving effect to the offering of units and the application of the related net proceeds, our net tangible book value was $ million, or $ 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		$
Pro forma net tangible book value per unit before the offering(1)	$
Increase in net tangible book value per unit attributable to purchasers in the offering
Less: Pro forma net tangible book value per unit after the offering(2)
Immediate dilution in net tangible book value per unit to new investors(3)		$

(1) Determined by dividing the total number of units held by Nami ( common units) and certain members of our management ( Class B units) into our net tangible book value.

(2) Determined by dividing the total number of common units to be outstanding after this offering (12,000,000 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 $ million and $ million, respectively.

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		50.0	%		$			%
Purchasers in this offering	6,000,000		50.0	%					%
Total	12,000,000		100.0	%		$		100.0	%

(1) Includes 460,000 Class B units, of which 240,000 Class B units have been issued to Scott W. Smith, our President and Chief Executive Officer, and 125,000 Class B units have been issued to Richard A. Robert, our Executive Vice President and Chief Financial Officer. The remaining Class B units have been reserved for additional management personnel that we intend to hire in the future. The total consideration for all of the units is equal to the net tangible book value as of December 31, 2006 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—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. 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 27.1% and 3.8%, respectively, of the outstanding common units (24.0% and 3.7% 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 expect that 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 expect that 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

We expect that the amount of the initial quarterly distribution will be $0.42 per unit, or $1.68 per year. 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	6,000,000	$	2,520,000	$	10,080,000	6,900,000	$	2,898,000	$	11,592,000
Distributions to Private Investors	2,290,000	961,800		3,847,200		2,103,989	883,675		3,534,702
Distributions to Nami	3,250,000	1,365,000		5,460,000		2,986,011	1,254,125		5,016,498
Distributions to management(1)	460,000	193,200		772,800		460,000	193,200		772,800
Total distributions paid	12,000,000	$	5,040,000	$	20,160,000	12,450,000	$	5,229,000	$	20,916,000

(1) Includes 460,000 Class B units, of which 240,000 Class B units have been issued to Scott W. Smith, our President and Chief Executive Officer, and 125,000 Class B units have been issued to Richard A. Robert, our Executive Vice President and Chief Financial Officer. 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 100,000 options to be granted to management at the time of our initial public offering under our Long-Term Incentive Plan.

We expect to pay the initial quarterly distribution on all of our outstanding units for each quarter through June 30, 2008. Within 45 days after the end of each quarter, beginning with the quarter ending September 30, 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 September 30, 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 June 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 June 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 June 30, 2008; and

· “Unaudited Pro Forma Cash Available to Pay Distributions,” in which we present the amount of available cash we would have generated on a pro forma basis in 2006.

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” 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 June 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 June 30, 2008. The assumptions disclosed in the footnotes to the table under the caption “—Estimated Cash Available to Pay Distributions—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 June 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”, 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 $0.42 per unit on all outstanding units for each full calendar quarter in the twelve-month period ending June 30, 2008.

Estimated Cash Available to Pay Distributions

In order to pay the initial quarterly distribution of $0.42 per unit per quarter for the twelve months ending June 30, 2008, our cumulative cash available to pay distributions must be at least $20.2 million ($20.9 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 June 30, 2008 must be at least $30.5 million ($31.3 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 $20.2 million ($20.9 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 $33.6 million for the twelve months ending June 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 June 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:

· Interest expense;

· Depreciation, depletion and amortization; and

· Change in fair value of derivative contracts.

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 June 30, 2008.

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 June 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 June 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 June 30, 2008.

When considering our Estimated Adjusted EBITDA for the twelve months ending June 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 June 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 June 30, 2008, assuming that the offering was consummated on July 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 June 30, 2008 in the table, footnotes below and the assumptions and consideration described beneath the table below are estimates.

	Twelve Months Ending June 30, 2008 (without underwriters’ overallotment)				Twelve Months Ending June 30, 2008 (with underwriters’ overallotment)
	(in thousands, except per unit amounts)
Estimated Adjusted EBITDA(a)		$	33,647			$	33,647
Less:
Cash interest expense		—				—
Maintenance capital expenditures(b)		(10,360		)		(10,360		)
Plus:
Borrowings		—				—
Estimated cash available to pay distributions		$	23,287			$	23,287
Estimated cash distributions:
Annualized initial quarterly distribution per unit		$	1.68			$	1.68
Distributions to public unitholders		$	10,080			$	11,592
Distributions to Private Investors		3,847				3,535
Distributions to Nami		5,460				5,016
Distributions to management(c)		773				773
Total estimated cash distributions		$	20,160			$	20,916
Excess		$	3,127			$	2,371

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

	Twelve Months Ending June 30, 2008
Net Production:
Total production (MMcfe)		4,398
Average daily production (Mcfe/d)		12,048
Average Natural Gas Sales Price per MMBtu:
Average NYMEX sales price (swap hedged volumes)		$	7.81
Average NYMEX sales price (unhedged volumes)		$	8.19
Percent of total production hedged at assumed price levels		60		%
Weighted average net sales price per Mcfe		$	9.92
Estimated Adjusted EBITDA (in thousands):
Total revenue		$	43,618
Production costs		(6,971		)
Selling, general and administrative expenses		(3,000		)
Estimated Adjusted EBITDA		$	33,647

(b) For purposes of this table, we are assuming that we will fund all of our maintenance capital expenditures for the twelve months ending June 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 June 30, 2008, although that may change if acquisition opportunities become available to us in that period.

(c) Includes 460,000 Class B units, of which 240,000 Class B units have been issued to Scott W. Smith, our President and Chief Executive Officer, and 125,000 Class B units have been issued to Richard A. Robert, our Executive Vice President and Chief Financial Officer. The remaining 95,000 Class B units will be issued to additional management personnel that we intend to hire in the future.

Assumptions and Considerations

Based upon the specific assumptions outlined below with respect to the twelve months ending June 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 June 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 new 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

· Our net production pro forma for the year ended December 31, 2006 was 4,378 MMcfe. We estimate that our total net production will remain relatively constant and will be approximately 4,398 MMcfe for the twelve months ending June 30, 2008, which is consistent with the forecasted production contained in our reserve report prepared by NSAI. The maintenance of a constant level of total net production for the twelve months ending June 30, 2008 compared to the pro forma for the year ended December 31, 2006 is attributable to our expected participation for our 40% working interest in the drilling of 195 gross (78 net) wells (or approximately 32.5 gross (13 net) wells per quarter) during 2007 and the six months ending June 30, 2008. During 2007 and the six months ending June 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 12,048 Mcfe for the twelve months ending June 30, 2008, which is consistent with the forecasted production contained in our reserve report prepared by NSAI. Pro forma for the year

ended December 31, 2006, our average net daily production was approximately 11,995 Mcfe. Pursuant to a participation agreement that we have entered into with Vinland, Vinland generally has control over our drilling program and the sole right to determine which wells are drilled until January 1, 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 a 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 net wells, in which we will own a 100% working interest, in a given quarterly period. Based on our production rate at December 31, 2006, we believe we need to drill approximately 130 gross wells (52 net wells) per year to maintain our production at current levels. If Vinland only drills its minimum commitment of 100 gross wells per calendar year, we believe that our total production will decline by approximately 2% to 3% per year over the next four years, after which our production will increase by approximately 6% in the fifth year. These declines and subsequent increase in our production together result in an approximate overall 4% decline in our production for the next five years. If Vinland drills its minimum commitment during the four year period, 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.

· We estimate that we will achieve a weighted average net sales price of approximately $9.92 per Mcfe for the twelve months ending June 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, our average net realized sales price was approximately $8.22 per Mcfe as compared to approximately $9.92 per Mcfe forecast for the twelve-month period ending June 30, 2008. 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 $8.19 per MMBtu (based on forward NYMEX curves as of March 14, 2007) and our executed swaps. For the twelve months ending June 30, 2008, approximately 60% of total production, or 2,660 MMcfe, is hedged using swap agreements at a weighted average price of $7.81 per MMBtu and approximately 34% of our production, or 1,515 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) $2.17 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) $1.80 per Mcfe over average NYMEX sales prices per MMBtu on swap hedged volumes relating to 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 $57.65 per Bbl (based on forward NYMEX curves as of March 14, 2007), 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 June 30, 2008.

· Pro forma for the year ended December 31, 2006, we generated total gross revenue of $36.0 million excluding the non-cash change in fair value of derivative contracts. The estimated increase in gross revenues to $45.6 million for the twelve months ending June 30, 2008 compared to the pro forma for the year ended December 31, 2006 of $36.0 million, is attributable to a small increase in estimated production, but principally from increases in the average natural gas and oil sales prices.

In addition, our gross revenues pro forma for the year ended December 31, 2006 were reduced as a result of realized hedging losses of $2.2 million. For the twelve months ending June 30, 2008, we estimate our gross revenues will be reduced as a result of realized hedging losses of $2.0 million.

Expenses

· 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 $5.1 million is comparable to $5.1 million for the pro forma results for the year ended 2006. 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 production tax rate of 4.39% is consistent with the production tax rate of 3% in Kentucky and 4.5% in Tennessee in 2006.

· We estimate that our selling, general and administrative expenses for the twelve months ending June 30, 2008 will be approximately $3.0 million, excluding the impact of non-cash unit based compensation charges for the Class B units granted to management in April 2007, 100,000 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, our selling, general and administrative expenses were $3.0 million. 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.

· Pro forma for the year ended December 31, 2006, we had no interest expense. We anticipate that after giving effect to the application of net proceeds from this offering, we will repay the $114.6 million outstanding under our reserve-based credit facility and there will be no outstanding balance on our reserve-based credit facility. If the underwriters exercise their option to purchase additional common units in full, we expect to have have an additional $7.7 million in cash after giving application to the net proceeds of this offering. If the underwriters do not exercise in full their option to purchase additional units, we will repay the outstanding borrowings and begin generating interest income on cash balances during the twelve months ending June 30, 2008. Giving effect to this offering and the application of the net proceeds therefrom, our borrowing capacity is expected to be $115.5 million under our reserve-based credit facility, assuming the current borrowing base of $115.5 million. We estimate that we will have sufficient capacity under our reserve-based credit facility for the twelve months ending June 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. 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.”

Capital Expenditures

· We estimate that our drilling capital expenditures for the twelve months ending June 30, 2008 will be approximately $10.4 million, based on our expectation of drilling 130 gross wells (52 net wells) during the year at an average cost of $199,235 per well with expected net 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 $2.4 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. The decrease in estimated capital expenditures for the twelve months ending June 30, 2008 compared to the year ended December 31, 2006 is attributable to the drilling of less net wells (52 as compared to 100), 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 June 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 June 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 4,398 MMcfe during the twelve months ending June 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 4,618 MMcfe or 4,178 MMcfe), we estimate that our estimated cash available to pay distributions would increase (decrease) by approximately $2.0 million, assuming no other changes in any 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 $8.19 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 $1.66 million to $25.0 million. If the average realized natural gas sales price for our net production volumes was to decrease by $1.00 per MMBtu, we estimate that our estimated cash available to pay distributions would decrease by approximately $1.52 million to $21.8 million. Of this $21.8 million, approximately 9% consists of realizations from our put options. Both scenarios assume we maintain hedges of approximately 60% of total production, or 2,660 MMcfe, using swap agreements at a weighted average price of $7.81 per MMBtu and approximately 34% of our production, or 1,515 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

The following table illustrates, on a pro forma basis, for the year ended December 31, 2006, 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. Pro forma cash available to pay distributions excludes any cash from working capital or other borrowings and cash on hand as of the closing date of this offering.

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)
	(in thousands except per unit amounts)				(in thousands except per unit amounts)
Net income		$	36,015			$	36,015
Unrealized loss on natural gas derivatives		(17,748		)		(17,748		)
Depreciation, depletion and amortization		7,927				7,927
Interest income		(40		)		(40		)
Interest expense		—				—
Adjusted EBITDA		$	26,154			$	26,154
Less:
Net cash interest expense		—				—
Maintenance capital expenditures(a)		(9,326		)		(9,326		)
Net revenue attributable to conveyed operations(a)		(3,106		)		(3,106		)
Plus:
Borrowings		—				—
Estimated cash available to pay distributions		$	13,722			$	13,722
Estimated cash distributions
Annualized initial quarterly distribution per unit		$	1.68			$	1.68
Distributions to Public Unitholders		$	10,080			$	11,592
Distributions to Private Investors		3,847				3,535
Distributions to Nami		5,460				5,016
Distributions to Management		773				773
Total estimated cash distributions		$	20,160			$	20,916
Shortfall		$	(6,438	)		$	(7,194	)

(a) In connection with the Nami Restructuring Plan, effective as of January 5, 2007, we retained a 40% working interest in approximately 107,000 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 1, 2007. During the twelve months ended December 31, 2006, we drilled 100 gross and net wells. If the Nami Restructuring Plan had been consummated as of January 1, 2006, these 100 wells would have been drilled only 40% net to our interest. Accordingly, the maintenance capital expenditures presented above only reflect 40% of our actual drilling expenditures, which were approximately $23.3 million. Additionally, we have reduced our net revenues attributable to wells drilled in 2006 by an estimate of the amount that would have been earned by Vinland pursuant to their 60% ownership interest in these wells if a 60% ownership interest in such wells was conveyed to Vinland as of January 1, 2006. Net revenue is defined as revenue less applicable lease operating expenses and taxes other than income incurred on the revenue.

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 September 30, 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 UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL DATA

Set forth below is our summary historical and unaudited pro forma consolidated financial and operating data for the periods indicated for Vanguard Natural Resources, LLC and 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 2003 are derived from the unaudited financial statements of our predecessor. The pro forma as adjusted statement of operations data gives effect to the separation of our predecessor and Vinland as part of the Nami Restructuring Plan, as well as our recent private placement, new reserve-based credit facility and this offering as if such transactions occurred on January 1, 2006. The pro forma as adjusted balance sheet data gives effect to these transactions offering as if they occurred on December 31, 2006.

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.

	Year Ended December 31,													Year Ended December 31, 2006
	2002				2003			2004			2005			Historical				Pro Forma As Adjusted
	(unaudited)																	(unaudited)
	(in thousands)
Statement of Operations Data:
Revenues:
Natural gas and oil sales		$	9,313		$	17,844		$	23,881		$	40,299			$	38,184			$	38,185
Realized losses on derivative contracts		—			(1,939		)	(5,926		)	(10,024		)		(2,208		)		(2,208		)
Change in fair value of derivative contracts(1)		—			—			(991		)	(18,779		)		17,748				17,748
Other		1,778			83			29			451				665				—
Total revenues		11,091			15,988			16,993			11,947				54,389				53,725
Costs and expenses:
Lease operating expenses		844			2,126			2,407			4,607				4,896				5,068
Depreciation, depletion and amortization		2,505			3,109			4,029			6,189				8,633				7,927
Selling, general and administrative expenses		3,172			3,454			3,154			5,946				5,199				3,024
Taxes other than income		302			505			611			1,249				1,774				1,731
Total costs and expenses		6,823			9,194			10,201			17,991				20,502				17,750
Income (loss) from operations		4,268			6,794			6,792			(6,044		)		33,887				35,975
Other Income and (Expenses):
Interest income		6			14			7			52				40				40
Interest and financing expenses		(1,506		)	(1,413		)	(1,455		)	(4,566		)		(7,372		)		—
Total other income and (expenses)		(1,500		)	(1,399		)	(1,448		)	(4,514		)		(7,332		)		40
Net income (loss)		$	2,768		$	5,395		$	5,344		$	(10,558	)		$	26,555			$	36,015
Cash Flow Data:
Net cash provided by operating activities(1)		$	6,997		$	7,058		$	9,607		$	10,530			$	16,087			$	—
Net cash used in investing activities		(7,613		)	(10,641		)	(19,598		)	(37,068		)		(37,383		)		—
Net cash provided by (used in) financing activities		5,699			(500		)	12,721			25,571				19,985				—
Other Financial Information (unaudited):
Adjusted EBITDA(2)		$	6,773		$	9,903		$	11,812		$	18,924			$	24,772			$	26,154

	As of December 31,									As of December 31, 2006
	2002			2003		2004		2005		Historical			Pro Forma As Adjusted
	(unaudited)												(unaudited)
	(in thousands)
Balance Sheet Data:
Cash and cash equivalents		$	5,362	$	1,279	$	4,009	$	3,041		$	1,731		$	888
Other current assets		3,778		6,473		10,033		19,598			20,438			7,095
Natural gas and oil properties, net of accumulated depreciation, depletion and amortization		32,766		39,555		54,761		83,513			104,684			95,350
Property, plant and equipment, net of accumulated depreciation		659		1,480		1,894		4,104			11,873			—
Other assets		—		—		—		—			—			5,255
Total assets		$	42,565	$	48,787	$	70,697	$	110,256		$	138,726		$	108,588
Short-term derivative contracts		$	—	$	—	$	800	$	11,527		$	2,022		$	2,022
Other current liabilities		2,297		3,545		6,347		12,033			11,505			8,528
Long-term debt		26,817		28,318		42,318		72,708			94,068			—
Long-term derivative contracts		—		—		191		8,243			—			—
Other long-term liabilities		—		78		130		212			418			418
Members’ capital		13,451		16,846		20,911		5,533			30,713			97,620
Total liabilities and members’ capital		$	42,565	$	48,787	$	70,697	$	110,256		$	138,726		$	108,588

(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.

We owned working interests in 845 gross (786 net) productive wells at December 31, 2006 and our average net production for the twelve months ended December 31, 2006 was 11,995 Mcfe per day. We also have a 40% working interest in approximately 107,000 gross undeveloped acres surrounding or adjacent to our existing wells located in southeast Kentucky and northeast Tennessee. Vinland owns the remaining 60% working interest in this acreage, as well as a 100% working interest in depths above and 100 feet below our known producing horizons and is expected to act 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% working interest. In addition, we own a contract right 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 oil and gas wells located in Bell and Knox Counties, Kentucky, which accounted for approximately 5% of our pro forma estimated proved reserves as of December 31, 2006. Our estimated pro forma proved reserves at December 31, 2006 were 66.0 Bcfe, of which approximately 97% were natural gas and 75% were classified as proved developed. Our properties, including our 40% working interest in approximately 107,000 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.

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 net wells, in which we will own a 100% working interest, in a given quarterly period. Based on our production rate at December 31, 2006, we believe we need to drill approximately 130 gross wells (52 net wells) per year to maintain our production at current levels. If Vinland only drills its minimum commitment of 100 gross wells per calendar year, we believe that our total production will decline by approximately 2% to 3% per year over the next four years, after which our production will increase by approximately 6% in the fifth year. These declines and subsequent increase in our production together result in an approximate overall 4% decline in our production for the next five years. If Vinland drills its minimum commitment during the four year period, 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 for five years 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 in four years, after which we each will have the right to propose the drilling of wells within the AMI and 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.”

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 will, advise and consult with us regarding all aspects of our production and development operations and provide 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 will reimburse 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 will reimburse us for selling, general and administrative expenses that we incurred on their behalf between January 5, 2007 and April 18, 2007. We will reimburse Vinland for certain transaction costs and expenses relating to entering into these agreements. Please read “Certain Relationships and Related Party Transactions.”

Nami Restructuring Plan

employees other than our President and Chief Executive Officer and our Executive Vice President and Chief Financial Officer. We retained all of our operating company’s proved producing wells and associated reserves along with the remaining 40% working interest in the approximately 107,000 gross undeveloped acres in the AMI as well as a contract right 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 in Bell and Knox Counties, Kentucky, which accounted for approximately 5% of our pro forma estimated proved reserves as of December 31, 2006. 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, which we refer to as the Private Investors, for $41.2 million. We used the net proceeds of this private equity offering to make a $37.2 million distribution to Nami, 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 $1.68 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 under which our initial borrowing base was set at $115.5 million of which $114.6 million was outstanding as of March 31, 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 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 of December 31, 2006, we had identified 325 additional proved undeveloped drilling locations and over 155 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 three and a half years. 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 a 40% working interest, in any quarter ending before January 1, 2011. For the twelve months ending June 30, 2008, we expect net production of approximately 4,398 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 swaps, costless collars and NYMEX put options to hedge natural gas prices. We have a costless collar in place for 79% of our expected natural gas and oil production from proved producing reserves from February through June of 2007. Our fixed-priced swaps hedge from July 1, 2007 through 2011 approximately 80% of our expected production from wells producing at December 31, 2006 at $7.69 per MMBtu. However, as a result of expected production from wells that began or are expected to begin producing after December 31, 2006, our fixed price swaps hedge approximately 60% of our expected production for the twelve month period ending June 30, 2008 at $7.81 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 swap contracts, costless collars 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 Class B units granted to management in April 2007, 100,000 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, will be approximately $3.0 million for the twelve months ending June 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 $1.4 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 June 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 a 60% working interest in approximately 107,000 gross undeveloped acres in the AMI, interests 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 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. Accordingly, the changes in the fair value of its derivative instruments are currently reflected in earnings.

· We will incur additional selling, general and administrative expense estimated to be $1.4 million per year for costs associated with being a public company. Also, we will incur non-cash compensation charges for the Class B units granted to management in April 2007, 100,000 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.

Results of Operations

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

	Year Ended December 31,
	2006				2005				2004
	(in thousands)
Revenues:
Natural gas and oil sales	$		38,184		$		40,299		$		23,881
Realized losses on derivative contracts	(2,208			)	(10,024			)	(5,926			)
Change in fair value of derivative contracts	17,748				(18,779			)	(991			)
Other	665				451				29
Total revenues	$		54,389		$		11,947		$		16,993
Costs and expenses:
Lease operating expenses	$	4,896			$	4,607			$	2,407
Depreciation, depletion and amortization	8,633				6,189				4,029
Selling, general and administrative expenses	5,199				5,946				3,154
Taxes other than income	1,774				1,249				611
Total costs and expenses	$		20,502		$		17,991		$		10,201
Other Income and (Expenses):
Interest expense, net	$		(7,332	)	$		(4,514	)	$		(1,448	)

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 the 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 118 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 $115.5 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 June 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 June 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 June 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 swaps, costless collars and NYMEX put options to hedge natural gas prices. We have a costless collar in place for 79% of our expected natural gas and oil production from proved producing reserves from February through June of 2007. Our fixed-priced swaps hedge from July 1, 2007 through 2011 approximately 80% of our expected production from wells producing at December 31, 2006 at $7.69 per MMBtu. However, as a result of expected production from wells that began or are expected to begin producing after December 31, 2006, our fixed price swaps hedge approximately 60% of our expected production for the twelve month period ending June 30, 2008 at $7.81 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 next to 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 ($/MMBtu)			Put Option Volumes (MMBtu)		Average Price ($/MMBtu)
Period from July 1, and February 1, 2007 through December 31, 2007 (1)		1,708,357		$	7.50		1,356,480		$	7.50
Period from January 1, 2008 through December 31, 2008		3,016,134		$	8.14		2,211,366		$	7.50
Period from January 1, 2009 through December 31, 2009		2,657,046		$	7.87		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.

	Collar Volumes (MMBtu)		Price Floor ($/MMBtu)			Price Ceiling ($/MMBtu)
Period from February 1, 2007 through June 30, 2007		1,500,000		$	6.45		$	7.45

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 March 31, 2007, we had $0.9 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 $115.5 million, assuming the current borrowing base of $115.5 million. Based upon management’s current natural gas price expectations for the twelve months ending June 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 June 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. 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 March 31, 2007, we had $114.6 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 puts 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.

We anticipate that $104.0 million of the net proceeds from this offering, and after giving effect to repayments we anticipate making prior to the closing of this offering, will be used to repay all amounts 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; and

· 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.

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) All outstanding debt as of December 31, 2006 was repaid with borrowings under a new reserve-based credit facility in January 2007.

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 March 31, 2007, we had debt outstanding of $114.6 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 $1.2 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.

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 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.

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.

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.

Derivative Instruments and Hedging 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 and puts. Additionally, we use derivative financial instruments in the form of interest rate swaps to mitigate our interest rate exposure. 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.

A put option requires us to pay the counterparty the fair value of the option at the purchase date and receive from the counterparty the excess, if any, of the fixed floor over the floating market price. The costs incurred to enter into the transactions are expensed as incurred, and the change in fair market value of the instrument is reported in the statement of operations each period.

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 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.

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 units which vest over three years. In addition, another 95,000 restricted units have been reserved for issuance to other members of management as they are retained. 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.

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 845 gross (786 net) productive wells at December 31, 2006 and our average net production for the twelve months ended December 31, 2006 was 11,995 Mcfe per day. We also have a 40% working interest in approximately 107,000 gross undeveloped acres surrounding or adjacent to our existing wells located in southeast Kentucky and northeast Tennessee. Vinland owns the remaining 60% working interest in this acreage, as well as a 100% working interest in depths above and 100 feet below our known producing horizons and is expected to act 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 this 40% working interest. In addition, we own a contract right to receive 100% of the net proceeds from the sale of production from certain oil and gas wells located in Bell and Knox Counties, Kentucky, which accounted for approximately 5% of our pro forma estimated proved reserves as of December 31, 2006. Our estimated pro forma proved reserves at December 31, 2006 were 66.0 Bcfe, of which approximately 97% were natural gas and 75% were classified as proved developed. Our properties, including our 40% working interest in approximately 107,000 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 pro forma proved reserves as of December 31, 2006 and our production for the year ended December 31, 2006. During 2006, we drilled 100 gross wells and as of December 31, 2006, we had identified 325 additional proved undeveloped drilling locations and over 155 other drilling locations on our leasehold acreage. Pursuant to a participation agreement that we have entered into with Vinland, Vinland generally has control over our drilling program and the sole right to determine which wells are drilled until January 1, 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 a 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 net wells, in which we will own a 100% working interest, in a given quarterly period. Based on our production rate at December 31, 2006, we believe we need to drill approximately 130 gross wells (52 net wells) per year to maintain our production at current levels. If Vinland only drills its minimum commitment of 100 gross wells per calendar year, we believe that our total production will decline by approximately 2% to 3% per year over the next four years, after which our production will increase by approximately 6% in the fifth year. These declines and subsequent increase in our production together result in an approximate overall 4% decline in production for the next five years. If Vinland drills its minimum commitment during the four year period, 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 for five years 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 in four years, after which we each will have the right to propose the drilling of wells within the AMI and 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.

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 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 December 31, 2006 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 producing wells. As of December 31, 2006, we had identified 325 proved undeveloped drilling locations and an additional 155 probable and possible locations on our approximately 107,000 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 three and a half years. 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 a 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 no outstanding long-term debt. We have entered into a reserve-based credit facility which will give us up to $115.5 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 100% of Vinland and, upon completion of this offering, Nami and certain of his affiliates and related persons will own a 27.1% 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. 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 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. As of December 31, 2006, 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 a 60% working interest in approximately 107,000 gross undeveloped acres in the AMI, interests 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 the participation agreement described below, 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. 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.”

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 will reimburse 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 will reimburse us for selling, general and administrative expenses that we incurred on their behalf between January 5, 2007 and April 18, 2007. We will reimburse 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 will advise and consult with us regarding all aspects of our production and development operations and provide us with administrative support services as necessary for the operation of our business. 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 Service 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 will 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 will 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. Please read “Conflicts of Interest and Fiduciary Duties.”

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 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 Columbia Gas Transmission system was $0.25 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, our average realized natural gas prices (before hedging), represented a $1.49 per Mcfe 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 predecessor’s estimated net proved natural gas and oil reserves and the present value of the estimated proved reserves at December 31, 2004, 2005 and 2006, based on reserve reports prepared by Wright & Company, Schlumberger Data and Consulting Services and NSAI, respectively. A summary of the reserve report related to estimated proved reserves at December 31, 2006 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.

	Predecessor									Pro Forma
	As of December 31,									As of December 31,
	2004			2005			2006			2006
Reserve Data:
Estimated net proved reserves:
Natural gas (Bcf)	73.6			107.7			94.2				64.3
Crude oil (MBbls)	39			464			343				287
Total (Bcfe)	73.8			110.5			96.3				66.0
Proved developed (Bcfe)	39.6			55.4			49.7				49.7
Proved undeveloped (Bcfe)	34.2			55.1			46.6				16.3
Proved developed reserves as% of total proved reserves	54		%	50		%	52		%		75		%
Standardized measure (in millions)(1)	$	173.0		$	400.4		$	148.8			$	120.9
Representative Natural Gas and Oil Prices(2):
Natural gas—NYMEX Henry Hub per MMBtu	$	5.96		$	9.89		$	5.63			$	5.63
Oil—NYMEX WTI per Bbl	$	40.46		$	58.11		$	57.75			$	57.75

(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, we paid NSAI approximately $50,000 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,
	2004		2005		2006
Net Production:
Total realized production (MMcfe)	2,911		3,894		4,378
Average daily production (MMcfe/d)	7,975		10,669		11,995
Average Realized Sales Prices ($per Mcfe):
Average sales prices (including hedges)	$	6.17	$	7.77	$	8.22
Average sales prices (excluding hedges)	$	8.20	$	10.35	$	8.72
Average Unit Costs ($per Mcfe):
Production costs	$	1.04	$	1.50	$	1.52
Selling, general and administrative expenses	$	1.08	$	1.53	$	1.19
Depreciation, depletion and amortization	$	1.38	$	1.59	$	1.97

Productive Wells

The following table sets forth information at December 31, 2006 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		832	774
Non-operated		13	12
Total		845	786

Developed and Undeveloped Acreage

The following table sets forth information as of December 31, 2006 relating to our leasehold acreage.

	Developed Acreage(1)			Undeveloped Acreage(2)			Total Acreage
	Gross(3)		Net(4)	Gross(4)		Net(4)	Gross	Net
Operated		21,740	21,740		84,789	84,789	106,529	106,529
Non-operated		260	65		—	—	260	65

(1) Developed acres are acres spaced or assigned to productive wells.

(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.

(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.

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 $199,235 in the twelve month period ending June 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 470 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. As of December 31, 2006, we had identified 325 additional proved undeveloped drilling locations and over 155 other drilling locations in this area. Assuming we drill approximately 130 of our identified drilling locations per quarter, we believe we will be able to maintain our current total production for approximately three and a half years. In 2007, we have budgeted $9.9 million for the participation of the drilling of approximately 130 gross wells (52 net wells), all of which will be operated by Vinland. Of those 130 wells, we estimate that 121 will be located in Kentucky and 9 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. 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,
	2004		2005		2006
Gross wells:
Productive		79		120		100
Dry		—		—		—
Total		79		120		100
Net Development wells:
Productive		76		111		96
Dry		—		—		—
Total		76		111		96
Net Exploratory wells:
Productive		3		9		4
Dry		—		—		—
Total		3		9		4

Operations

General

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 a participation agreement that we have entered into with Vinland, Vinland generally has control over our drilling program and the sole right to determine which wells are drilled until January 1, 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 a 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 net wells, in which we will own a 100% working interest, in a given quarterly period. Based on our production rate at December 31, 2006, we believe we need to drill approximately 130 gross wells (52 net wells) per year to maintain our production at current levels. If Vinland only drills its minimum commitment of 100 gross wells per calendar year, we believe that our total production and our production will decline by approximately 2% to 3% per year over the next four years, after which our production will increase by approximately 6% in the fifth year. These declines and subsequent increase in our production together result in an approximate overall 4% decline in our production for the next five years. If Vinland drills its minimum commitment during the four year period, 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 for five years 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 in four years, after which we each will have the right to propose the drilling of wells within the AMI and 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

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 swaps, costless collars and NYMEX put options to hedge natural gas prices. We have a costless collar in place for 79% of our expected natural gas and oil production from proved producing reserves from February through June of 2007. Our fixed-priced swaps hedge from July 1, 2007 through 2011 approximately 80% of our expected production from wells producing at December 31, 2006 at $7.69 per MMBtu. However, as a result of expected production from wells that began or are expected to begin producing after December 31, 2006, our fixed price swaps hedge approximately 60% of our expected production for the twelve month period ending June 30, 2008 at

$7.81 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, 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.

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 January 31, 2007, we had two full time employees and one contract employee. 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 January 31, Vinland had 26 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.

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. The parties have exchanged discovery requests.

In connection with the Nami Restructuring Plan, we received a contract right to receive 100% 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 December 31, 2006. 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 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.

MANAGEMENT

Our Board of Directors

Upon completion of this offering, our board of directors will consist of five members, three 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 Messrs. , and as independent directors and as members of the audit committee, the compensation committee, the conflicts committee and the nominating committee immediately following the pricing of this offering. The current members and the independent members of the board expected to be appointed immediately following the pricing of this offering will be subject to re-election annually as described below. 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. 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, all members of the audit committee will be independent under the independence standards established by NYSE Arca and SEC rules, and the committee expects to have an “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, all members of the compensation committee 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 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, at least one member of the nominating committee 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 and we also reimburse Vinland for the reasonable costs of the services it provides to us. 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.” 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 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

Our board of directors expects that our audit committee will have an “audit committee financial expert.”

Executive Sessions of Board

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 managers. During such executive sessions, one manager is designated as the “presiding manager” and is 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. Our board of directors determined executive compensation.

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 each annual meeting of unitholders.

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 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
Thomas M. Blake	57	Director
Lasse Wagene	35	Director
Michael J. Cannon	45	Director

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.

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 provider of mid-stream assets, 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. 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 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.

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 taking into account 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, all members of the compensation committee 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.

During fiscal year 2006, we had no compensation committee. Nami, as our sole owner, determined executive compensation for our President and Chief Executive Officer, which was our only officer in fiscal year 2006.

Elements of Compensation

Executive compensation consists of following elements:

Base Salary. Base salaries for our executives are established based on the scope of their responsibilities, taking into account competitive market compensation paid by other companies for similar positions. Generally, we believe that executive base salaries should be targeted near the median of the range of salaries for executives in similar positions with similar responsibilities at comparable companies, in line with our compensation philosophy. Base salaries are reviewed annually, and adjusted from time to time to realign salaries with market levels after taking into account individual responsibilities, performance and experience.

Annual Bonuses. All of our executive officers and other employees are eligible for annual cash bonuses, which are paid at the discretion of our compensation committee. The employment agreements with our executive officers do not provide for minimum bonuses. The determination of the amount of annual bonuses paid to our executive officers generally reflects a number of subjective considerations, including the performance of our company overall and the contributions of the executive officer during the relevant period.

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 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 may 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 the prior 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 each year. Specific performance targets used to determine incentive compensation for each of our executive officers in 2007 have not yet been determined.

Other Employee Grants. Prior to the completion of this offering, we intend to grant to Richard A. Robert options to purchase an aggregate of 100,000 units under our long-term incentive plan with an exercise price equal to the public offering price in this offering that will vest in equal installments over a three year period beginning on the first anniversary of the completion of this offering. We also intend to grant to certain executive officers, pursuant to their employment agreements, an annual grant of phantom units in an amount 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. Each employment agreement provides 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

Scott W. Smith. We have entered into an employment agreement with Scott W. Smith, who will serve as our President and Chief Executive Officer. 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.

Commencing in 2008, Mr. Smith will receive an annual grant of phantom units in an amount equal to 1.0% of the outstanding units. 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 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. 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. 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 an annual grant of phantom units in an amount equal to 1.0% of the outstanding units. 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 is included as an exhibit to the registration statement of which this prospectus is a part.

These agreements were negotiated between the executive officers and Nami using a comparison of compensation packages from companies in our industry of similar size and stage of development.

Grants of Plan-Based Awards

Prior to the completion of this offering, we intend to grant to Richard A. Robert options to purchase an aggregate of 100,000 units 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. On January 1, 2008, we also intend to grant to our executive officers 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 and restricted units we plan to make under our long-term incentive 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 (#)		All Other Option Awards: Number of Securities Underlying Options (#)		Exercise or Base Price of Option Awards ($/unit)
Scott W. Smith	April 18, 2007		240,000		—	—
Richard A. Robert	April 18, 2007		125,000		100,000
All executive officers and directors as a group			365,000		100,000

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 500,000 units. The plan will be administered by the compensation committee of our board of directors.

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.

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.

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 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 460,000 Class B units to be issued to management. We issued 240,000 Class B units and 125,000 Class B units to Messrs. Smith and Robert, respectively. The Class B units will

100

have substantially the same rights as the common units and, upon vesting, will become convertible at the election of the holder into common units. The remaining Class B units have been reserved for issuance to additional management personnel that we intend to hire in the future. 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.

Termination due to Death or Disability. If the executive officer’s employment is terminated due to his death or disability, the executive, his beneficiary or his estate, as applicable, 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

101

compensation and reimbursements) and (4) a payment equal to the executive officer’s base salary for 12 months.

Termination Without Cause or For Good Reason. If the executive is terminated without cause during the term of the agreement, or 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 upon a Change of Control.

Early Termination Option. In the event our IPO 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 IPO. 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 IPO. In the event a change of control occurs after our IPO (our IPO 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.

Termination for Cause or other than for Good Reason. Upon termination for any other reason, the executive officer is only entitled to accrued compensation and reimbursements.

Estimated Payments to Executives. Assuming that (1) we had entered the employment agreements with the executive officers identified in “—Executive Compensation—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 $ per unit, the midpoint of the range set forth on the cover page of this prospectus, payments and benefits owed to such executives would have an estimated value as set forth in the tables below.

Scott W. Smith

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

102

Richard A. Robert

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

Compensation of Directors

Each independent member of our board of directors will receive 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 determined prior to completion of this offering. 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.

103

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, the Nami Restructuring Plan and the April 2007 private placement, 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)(3)		Percentage of Units to be Beneficially Owned
Nami Capital Partners, LLC(3)(4)		1,171,430		9.8
Majeed S. Nami(3)(6)		2,142,985		17.9
Majeed S. Nami Personal Endowment(3)(5)		971,555		8.1
Majeed S. Nami Irrevocable Trust(3)(5)		1,107,015		9.2
Scott W. Smith(7)		240,000		2.1
Richard A. Robert(7)		125,000		1.0
Thomas M. Blake		—		—
Lasse Wagene		—		—
Lehman Brothers MLP Partners, L.P.(8)		1,145,000		9.5
Third Point Partners LP(9)		1,145,000		9.5
Third Point Partners Qualified LP(9)		1,145,000		9.5
BLRTQS Partners(9)		1,145,000		9.5
All directors and executive officers as a group (4 persons)		365,000		3.0

* 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) 95,000 restricted units have been reserved for issuance to other members of management as they are retained.

(3) If our expected initial quarterly distribution at the time of this offering is less than $ 0.4375 per common unit, the Nami-related entities are obligated to convey the Private Investors approximately

104

27,480 additional common units. Currently, our board of directors has adopted a cash distribution policy to pay a regular quarterly distribution of $0.42 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 November 14, 2007 for the period from the closing of this offering through September 30, 2007. We will adjust our first distribution based on the actual length of that period.

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

(5) 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.

(6) 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.

(7) Comprised of 240,000 Class B units that have been issued to Scott W. Smith, our President and Chief Executive Officer, and 125,000 Class B units that have been issued to Richard A. Robert, our Executive Vice President and Chief Financial Officer. 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.

(8) Lehman Brothers MLP Partners, L.P. can be contacted at the following address: 390 Park Avenue, Ninth Floor, New York, New York 10022

(9) Third Point Partners Qualified LP, Third Point Partners LP and BLRTQS Partners are affiliates and each may be deemed to be a beneficial owner of the common units held by the others. Third Point Partners Qualified LP, Third Point Partners LP and BLRTQS Partners can be contacted at the following address: 390 Park Avenue, New York, New York 10022.

We will use 50% of any net proceeds from the exercise of the underwriters’ option to purchase a number of units from Nami and the Private Investors, in proportion to their respective ownership positions, equal to 50% of the number of units issued upon the exercise of the underwriters’ option. If the underwriters’ option to purchase additional units is exercised in full, Nami’s ownership of units will be reduced from 3,250,000 units to 2,986,011 units, or 24.0% of all then outstanding units, the Private Investors’ ownership of units will be reduced from 2,290,000 units to 2,103989 units, or 16.9% of all then outstanding units, and the ownership interest of the public unitholders will increase to 6,900,000 units, or 55.4% of all the outstanding units. The remaining net proceeds, if any, from the exercise of the underwriters’ option to purchase additional units will be used for working capital and general corporate purposes.

105

CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

Management Services Agreement

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 will advise and consult with us regarding all aspects of our production and development operations, and provide 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 and we also reimburse Vinland for the reasonable costs of the services it provides to us. 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. 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.

Participation Agreement

Pursuant to a participation agreement that we have entered into with Vinland, Vinland generally has control over our drilling program and the sole right to determine which wells are drilled until January 1, 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 a 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 net wells, in which we will own a 100% working interest, in a given quarterly period. Based on our production rate at December 31, 2006, we believe we need to drill approximately 130 gross wells (52 net wells) per year to maintain our production at current levels. If Vinland only drills its minimum commitment of 100 gross wells per calendar year, we believe that our total production will decline by approximately 2% to 3% per year over the next four years, after which our production will increase by approximately 6% in the fifth year, These declines and subsequent increases in our production together result in an approximate overall 4% decline in our production for the next five years. If Vinland drills its minimum commitment during the four year period, 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 for five years 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 in four years, after which we each will have the right to propose the drilling of wells within the AMI and 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

106

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.

Gathering and Compression Agreement

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 will 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 will pay Vinland Gathering 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. 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.

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

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.

107

Well Services Agreements

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.

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 us 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. In addition, Nami Resources and Vinland have agreed to provide for the defense of any such claims against 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 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, which accounted for approximately 5% of our pro forma estimated proved reserves as of December 31, 2006.

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.

108

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

We expect to enter into our omnibus agreement by which Nami will indemnify us against certain losses.

109

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.” 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

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.

110

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 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

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 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.

111

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.

112

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 five 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

113

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;

114

· 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,

115

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 “Cash Distribution Policy—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.

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.”

116

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.

117

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.

118

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 this offering. Please read “Units Eligible for Future Sale.”

119

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

122

(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 % 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; and

(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.

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 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.

123

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.

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.

124

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 [·]% 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.

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.”

125

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 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

126

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.

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

127

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;

· 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.”

128

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.

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 adopt as to property other than certain goodwill 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 to be depreciated over the remaining cost recovery period for the Section 704(c) built-in gain. If we elect a method other than the remedial method with respect to a goodwill property, Treasury Regulation Section 1.197-2(g)(3) generally requires that the Section 743(b) adjustment attributable to an amortizable Section 197 intangible, which includes goodwill property, should be treated as a newly-acquired asset placed in service in the month when the purchaser acquires the unit. 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 partnership agreement, we are authorized to take a position to preserve the uniformity of units even if that position is not consistent with these and any other Treasury Regulations. If we elect a method other than the remedial method with respect to a goodwill property, the common basis of such property is not amortizable. 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

129

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, and Treasury Regulation Section 1.197-2(g)(3). 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.

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

130

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.

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

131

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.”

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

132

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.

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.”

133

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.

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 capital gain or loss. Capital gain recognized by an individual on the sale of units held more than twelve months will generally be taxed at a maximum rate of 15%. 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

134

Internal Revenue Code to the extent attributable to assets giving rise to “unrealized receivables” or “inventory items” that we own. The term “unrealized receivables” includes potential recapture items, including depreciation, depletion, and IDC recapture. Ordinary income attributable to unrealized receivables and inventory items may exceed net taxable gain realized on the sale of a unit and may be recognized even if there is a net taxable loss realized on the sale of a unit. Thus, a unitholder may recognize both ordinary income and a capital loss upon a sale of units. Net capital loss may offset capital gains and no more than $3,000 of ordinary income, in the case of individuals, and may 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.

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.

135

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.

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) and Treasury Regulation Section 1.197-2(g)(3). 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

136

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, and Treasury Regulation Section 1.197-2(g)(3). 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 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

137

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. 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 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.

138

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 to us.

Accuracy-Related Penalties

An additional tax equal to 20% of the amount of any portion of an underpayment of tax that is attributable to one or more specified causes, including negligence or disregard of rules or regulations, substantial understatements of income tax and substantial valuation misstatements, is imposed by the Internal Revenue Code. No penalty will be imposed, however, for any portion of an underpayment if it is shown that there was a reasonable cause for that portion and that the taxpayer acted in good faith regarding that portion.

For individual 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 200% 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 400% or more than the correct valuation, the penalty imposed increases to 40%.

139

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. We may also own property or do business in other states in the future. Although an analysis of 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.

140

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.

141

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.









Total		6,000,000

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 900,000 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.

142

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 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 % 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 and Nami 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. Among the factors considered in determining the initial public offering price will be 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.

We intend to apply to list our common units 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 $ (or $ 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 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

143

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 and Nami (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.

144

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 was prepared by Netherland Sewell & Associates Inc., independent petroleum engineers, as stated in their reserve report with respect thereto. The reserve report of Netherland Sewell & Associates Inc for our reserves as of December 31, 2006 is attached hereto as Appendix D, 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 was prepared by Wright & Company, 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 was prepared by Schlumberger Data and Consulting Services, 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.

145

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-4

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-7

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.

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.

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.

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-8

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-9

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

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.

F-10

Vanguard Natural Gas, LLC and Subsidiaries
Notes to the Consolidated Financial Statements (Continued)

1. Summary of Significant Accounting Policies (Continued)

Asset Retirement Obligations

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-11

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-12

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-13

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.

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 (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-14

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 NYMEX 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-15

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-16

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-17

Vanguard Natural Gas, LLC and Subsidiaries
Notes to the Consolidated Financial Statements (Continued)

9. Subsequent Events (Continued)

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. 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-18

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 Shares

Effective January 5, 2007, we conveyed to Vinland Energy East, LLC and its affiliates a 60% working interest in approximately 107,000 gross acres 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 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 along with the remaining 40% working interest in the 107,000 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 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.

F-19

Vanguard Natural Gas, LLC and Subsidiaries
Notes to the Consolidated Financial Statements (Continued)

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-20

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, discoveries and other	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, discoveries and other	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, discoveries and other	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

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 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.

F-21

Vanguard Natural Gas, LLC and Subsidiaries
Notes to the Consolidated Financial Statements (Continued)

10. Supplemental Natural Gas and Oil Information (unaudited)

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.

F-22

Vanguard Natural Resources, LLC
Unaudited Pro Forma Consolidated Balance Sheet
As of December 31, 2006

				Conveyed						Financing
				Operations						Transactions			Vanguard
	Predecessor			Pro Forma				Vanguard		Pro Forma			Pro Forma
	Historical			Adjustments (a)				Pro Forma		Adjustments			As Adjusted
Assets
Current assets
Cash and cash equivalents	$	1,730,956			$	711		$	1,731,667	$	1,675,987 (2,520,000	(e) )(f)	$	887,654
Trade accounts receivable	5,269,067				(5,102		)	5,263,965		—			5,263,965
Receivables due from affiliates	14,650,936				(14,650,936		)	—		—			—
Other receivables	234,456				(234,456		)	—		—			—
Inventory	106,359				(106,359		)	—		—			—
Other current assets	177,525				(177,525		)	—		1,831,248		(b)	1,831,248
Total current assets	22,169,299				(15,173,667		)	6,995,632		987,235			7,982,867
Property and equipment
Land	46,350				(46,350		)	—		—			—
Buildings	10,850				(10,850		)	—		—			—
Furniture and fixtures	846,580				(846,580		)	—		—			—
Machinery and equipment	12,681,363				(12,681,363		)	—		—			—
Less: accumulated depreciation	(1,712,535		)		1,712,535			—		—			—
Net property and equipment	11,872,608				(11,872,608		)	—		—			—
Natural gas and oil properties, net—full cost method	104,683,610				(9,333,965		)	95,349,645		—			95,349,645
Other assets	—				—			—		452,500 4,622,348 180,195		(b) (b) (b)	5,255,043
Total assets	$	138,725,517			$	(36,380,240	)	$	102,345,277	$	6,242,278		$	108,587,555
Liabilities and members’ equity
Current liabilities
Accounts payable—trade	$	8,756,937			$	(1,880,248	)	$	6,876,689	—			$	6,876,689
Accounts payable—natural gas and oil	1,441,941				—			1,441,941		—			1,441,941
Derivative contracts	2,022,079				—			2,022,079		—			2,022,079
Accrued expenses	1,230,686				(2,980		)	1,227,706		(1,018,694		)(b)	209,012
Due to member	75,000				(75,000		)	—		—			—
Total current liabilities	13,526,643				(1,958,228		)	11,568,415		(1,018,694		)	10,549,721
Long-term debt	94,067,500							94,067,500		(94,067,500		)(b)	—
New reserve-based credit facility	—				—			—		107,424,013 (107,424,013		(b) )(e)	—
Asset retirement obligations	418,533				—			418,533		—			418,533
Total liabilities	108,012,676				(1,958,228		)	106,054,448		(95,086,194		)	10,968,254
Commitments and contingencies

F-24

Vanguard Natural Resources, LLC
Unaudited Pro Forma Consolidated Balance Sheet (Continued)
As of December 31, 2006

Members’ equity (deficit)	30,712,841		(34,422,012		)	(3,709,171		)	(5,251,528 (41,220,000 (8,280,000 (1,365,000		)(b) )(c) )(d) )(f)	(59,825,699		)
Common unitholders:
Public unitholders	—		—			—			120,000,000 (8,400,000 (2,500,000		(e) )(e) )(e)	109,100,000
Private investors	—		—			—			41,220,000 (961,800		(c) )(f)	40,258,200
Management	—		—			—			8,280,000 (193,200		(d) )(f)	8,086,800
Total liabilities and members’ equity	$	138,725,517	$	(36,380,240	)	$	102,345,277		$	6,242,278		$	108,587,555

See notes to unaudited pro forma consolidated financial statements

F-25

Vanguard Natural Resources, LLC
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 (a)				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				(3,524,602		)	1,674,158			1,350,000		(g)	3,024,158
Taxes other than income	1,774,215				(42,994		)	1,731,221			—			1,731,221
Total costs and expenses	20,502,537				(4,102,776		)	16,399,761			1,350,000			17,749,761
Income from operations	33,886,520				3,438,107			37,324,627			(1,350,000		)	35,974,627
Other income (expense)
Interest income	40,256				—			40,256			—			40,256
Interest expense	(7,371,930		)		—			(7,371,930		)	7,371,930		(h)	—
Total other expense	(7,331,674		)		—			(7,331,674		)	7,371,930			40,256
Net income	$	26,554,846			$	3,438,107		$	29,992,953		$	6,021,930		$	36,014,883
Computation of net income per common unit:
Net income per common unit (basic and diluted) (Note 3)														$	3.00
Weighted average common units outstanding:
Principal member														3,250,000
Private investors														2,290,000
Management														460,000
Public														6,000,000
Total														12,000,000

See notes to unaudited pro forma consolidated financial statements

F-26

VANGUARD NATURAL RESOURCES, LLC.
NOTES TO UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Note 1. Basis of Presentation, the Offering and Other Transactions

The historical financial information is derived from the audited historical consolidated financial statements of VNG the Predecessor to Vanguard. The pro forma consolidated balance sheet adjustments have been prepared as if the transactions effected had taken place on December 31, 2006, 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 on January 1, 2006.

The pro forma consolidated financial statements give effect to the following transactions:

· the retention by Vanguard of 100% of the producing wells and 100% of the related proved producing reserves and 40% of 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 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 borrowing of $107.4 million under a new reserve-based credit facility in January 2007 to refinance our pre-existing credit facilities and to fund costs associated with the termination of existing hedging arrangements and the entry into new hedging arrangements including fees for new natural gas put contracts;

· the repayment of all amounts owed under the previous long-term credit facilities and related fees and expenses including an early prepayment premium and fees to terminate existing natural gas swap contracts among others more fully described below;

· 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. Current management received 365,000 Class B units and the remaining 95,000 Class B units are reserved for issuance to new employees expected to be hired;

· the sale by Vanguard of 6,000,000 common units to the public in the initial public offering and the application of the proceeds more fully described below.

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 $1.35 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. Also, a one time non-recurring $1,225,377 litigation settlement expense incurred by the Predecessor in 2006 is not

F-27

VANGUARD NATURAL RESOURCES, LLC.
NOTES TO UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)

Note 1. Basis of Presentation, the Offering and Other Transactions (Continued)

considered in Vanguard’s continuing selling, general and administrative expenses in the unaudited pro forma consolidated financial statements.

Vanguard will reimburse Vinland $60 per well per month (in addition to normal third-party operating costs) for operating our current producing 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 on or prior to 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.

Note 2. Pro Forma Adjustments and Assumptions

(a) 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 the proved undeveloped reserves on leases within the AMI, (iii) Midstream Operations and (iv) affiliate balances. Also, all of the Predecessor employees, other than two officers, were transferred to Vinland. Assets (ie. trade accounts receivable, inventory, property and equipment, etc.) and liabilities (i.e. 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 and infrastructure 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.

(b) Reflects $107,424,013 in borrowings under a new reserve-based credit facility in January 2007 and the utilization of the cash as follows:

Repayment of debt under old credit facilities	$	94,067,500
Payment of December 31, 2006 accrued interest expense	1,018,694
Cash security for outstanding letters of credit	452,500
Penalty for the early prepayment of debt	2,501,528
Fee for the early termination of existing natural gas swaps	2,750,000
Fee for $7.50 MMBtu natural gas puts in 2007	1,831,248
Fee for $7.50 MMBtu natural gas puts in 2008 and 2009	4,622,348
Deferred financing costs	180,195
Total	$	107,424,013

F-28

VANGUARD NATURAL RESOURCES, LLC.
NOTES TO UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)

Note 2. Pro Forma Adjustments and Assumptions (Continued)

The $2,501,528 penalty for the early prepayment of debt and the $2,750,000 fee for the early termination of existing natural gas swaps are considered one time non-recurring expenses and as such are not reflected in the unaudited pro forma statement of operations. However, their combined impact of $5,251,528 is reflected as a reduction of members’ equity on the unaudited pro forma balance sheet.

(c) Reflects the sale 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.

(d) Reflects the reserving for a grant of 460,000 Class B units to Vanguard management in April 2007. Current management received 365,000 Class B units and the remaining 95,000 Class B units are reserved for issuance to new employees expected to be hired.

(e) Reflects the issuance and sale of 6,000,000 common units at an assumed initial offering price of $20.00 for total proceeds of $120,000,000. The application of proceeds are expected as follows:

Underwriting discount	$	8,400,000
Estimated offering related expenses	2,500,000
Repayment of borrowings under new credit facility	107,424,013
Working capital	1,675,987
Total	$	120,000,000

(f) Reflects the payment of accrued distributions to the principal member, private investors, and management in conjunction with the completion of the initial public offering. Pursuant to the terms of the private placement, all holders of units begin accruing distributions upon the closing of the sale of common units to the private investors at a rate of $1.68 annually. When the initial public offering is completed, the accrued distribution will be paid to all parties. It is assumed that one calendar quarter will lapse between the closing of the sale of common units to the private investors and the completion of the initial public offering.

(g) Reflects estimated additional incremental expenses associated with ongoing administration of Vanguard as a publicly held entity.

(h) Reflects the removal of all interest expense incurred on long-term debt as a result of the repayment of all outstanding debt balances with the proceeds of the initial public offering.

Note 3. Pro Forma Net Income per Unit

Net income per unit is not presented for the Predecessor as the entity was owned by one individual, the principal member. 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 January 1, 2006. Basic and diluted pro forma net income per unit is equivalent because there are no dilutive units at the date of closing of the initial public offering of the common units of Vanguard.

F-29

VANGUARD NATURAL RESOURCES, LLC.
NOTES TO UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)

Note 4. Supplemental Natural Gas and Oil Information (unaudited)

The following information summarizes the net proved reserves of natural gas and oil and the present values thereof as of December 31, 2006 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 for the year ended December 31, 2006.

	December 31, 2006
	Historical				Conveyed Operations				Vanguard Pro Forma
Proved Reserves	Oil (Bbls)		Gas (Mcf)		Oil (Bbls)		Gas (Mcf)		Oil (Bbls)		Gas (Mcf)
Beginning balance	463,693		107,690,281		141,113		34,963,515		322,580		72,726,766
Revisions of previous estimates	(106,630	)	(17,529,333	)	(84,938	)	(5,093,243	)	(21,692	)	(12,436,090	)
Extensions, discoveries and other	18,623		8,205,425		—		—		18,623		8,205,425
Production	(32,718	)	(4,181,708	)	—		—		(32,718	)	(4,181,708	)
Ending balance	342,968		94,184,665		56,175		29,870,272		286,793		64,314,393
Proved Developed Reserves
Beginning balance	246,595		53,900,263		—		—		246,595		53,900,263
Ending balance	249,329		48,166,327		—		—		249,329		48,166,327

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 is presented below:

F-30

VANGUARD NATURAL RESOURCES, LLC.
NOTES TO UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)

Note 4. Supplemental Natural Gas and Oil Information (unaudited) (Continued)

	December 31, 2006 (in thousands)
	Historical			Conveyed Operations				Vanguard Pro Forma
Future cash inflows	$	663,604			$	205,834			$	457,770
Future development costs	(66,906		)		(43,389		)		(23,517		)
Future production expense	(192,520		)		(55,754		)		(136,766		)
Future net cash flows	404,178				106,691				297,487
Discounted at 10% per year	(255,357		)		(78,764		)		(176,593		)
Standardize measure of discounted future net cash flows	$	148,821			$	27,927			$	120,894

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.

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. 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-31

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

March 30, 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 December 31, 2006, 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 December 31, 2006, to be:

	Net Reserves		Future Net Revenue ($)
	Oil	Gas		Present Worth
Category	(Barrels)	(MCF)	Total	at 10%
Proved Developed
Producing	185,039	47,017,106	233,202,200		103,390,400
Non-Producing	64,290	1,134,991	7,891,300		3,828,000
Proved Undeveloped	37,464	16,162,296	56,393,400		13,675,300
Total Proved	286,793	64,314,393	297,486,900		120,893,700

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. Reserve 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 December 31, 2006, West Texas Intermediate posted price of $57.75 per barrel and is adjusted for quality, transportation fees, and a regional price differential. Gas prices used in this report are based on a December 31, 2006, Columbia Gas Appalachia spot market price of $5.625 per MMBTU and are adjusted by field for energy content and transportation fees. 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. No 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 analogies to similar production. Because such reserve estimates are usually subject to greater revision than those based on substantial production and pressure data, 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/ FREDERIC D. SEWELL, P.E.
			Frederic D. Sewell, P.E.
			Chairman and Chief Executive 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: March 30, 2007		Date Signed: March 30, 2007

DDS: LRG


	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

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 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 54.2% 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 38.2% 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:

Purchaser	Purchase Price			Percentage Sharing Ratio Represented by membership Interests Purchased
Scott W. Smith		$	—		4.0	%
Richard A. Robert		—			2.1
Lehman Brothers MLP Partners, L.P.		20,610,000			19.1
Third Point Partners LP		10,016,460			9.3
Third Point Partners Qualified LP		8,532,540			7.9
BLRTQS Partners		2,061,000			1.9
Nami Capital Partners, LLC		—			19.5
Majeed S. Nami Personal Endowment		—			16.2
Majeed S. Nami Irrevocable Trust		—			18.5

(1)

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

II-2

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 and Trust Energy Company, LLC
10.18	—	Indemnity Agreement by and between Nami Resources Company, L.L.C., Vinland Energy Eastern, LLC and Trust Energy Company, 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
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.
23.4*	—	Consent of Vinson & Elkins L.L.P.
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)

* To be filed by amendment.

II-3

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.

II-4

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

Title of Each Class of Securities To Be Registered	Proposed Maximum Aggregate Offering Price(1)(2)			Amount of Registration Fee
Common units representing limited liability company interests		$	144,900,000		$	4,449

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

		Page

Vanguard Natural Gas, LLC and Subsidiaries Consolidated Financial Statements
Reports of Independent Registered Public Accounting Firms		F-2
Consolidated balance sheet		F-4
Consolidated statement of operations		F-5
Consolidated statement of members’ equity		F-6
Consolidated statement of cash flows		F-7
Notes to the consolidated financial statements		F-8
Vanguard Natural Resources, LLC Unaudited Pro Forma Consolidated Financial Statements		F-23
Unaudited Pro Forma Consolidated Balance Sheet		F-24
Unaudited Pro Forma Consolidated Statement of Operations		F-26
Notes to Unaudited Pro Forma Consolidated Financial Statements		F-27
Vanguard Natural Resources, LLC Balance Sheet
Report of Independent Registered Public Accounting Firm		F-32
Balance Sheet		F-33
Notes to Balance Sheet		F-34

Prospectus Summary		1
Vanguard Natural Resources, LLC		1
Business Strategies		3
Competitive Strengths		3
Our Relationship with Vinland		3
Cash Distribution Policy		5
Summary of Risk Factors		6
Nami Restructuring Plan		6
Private Placement		6
Reserve-Based Credit Facility		6
Our LLC Structure		6
The Offering		9
Summary Historical and Unaudited Pro Forma Consolidated Financial And Operating Data		14
Summary Reserve and Operating Data		16
Non-GAAP Financial Measure		17
Risk Factors		18
Risks Related to Our Business		18
Risks Related to Our Structure		32
Tax Risks to Unitholders		35
Cautionary Note Regarding Forward-Looking Statements		38
Use of Proceeds		39
Capitalization		40
Dilution		41
Cash Distribution Policy and Restrictions on Distributions		42
General		42
Our Initial Quarterly Distribution Rate		44
Financial Forecast		45
Estimated Cash Available to Pay Distributions		46
Sensitivity Analysis		51
Unaudited Pro Forma Cash Available to Pay Distributions		52
How We Make Cash Distributions		54
Distributions of Available Cash		54
Definition of Available Cash		54
Distributions of Cash Upon Liquidation		54
Adjustments to Capital Accounts		54
Management’s Discussion and Analysis of Financial Condition and Results of Operations		57
Overview		57
Nami Restructuring Plan.		58
Private Offering		59
Reserve-Based Credit Facility.		59
Comparability of Financial Statements		61
Results of Operations		62
Year Ended December 31, 2006 Compared to Year Ended December 31, 2005		62
Year Ended December 31, 2005 Compared to the Year Ended December 31, 2004		63
Capital Resources and Liquidity		64
Cash Flow from Operations		65
Investing Activities—Acquisitions and Capital Expenditures		66
Financing Activities		66

Quantitative and Qualitative Disclosure About Market Risk		69
Critical Accounting Policies and Estimates		70
Natural Gas and Oil Properties		70
Asset Retirement Obligations		71
Natural Gas and Oil Reserve Quantities		71
Revenue Recognition		71
Derivative Instruments and Hedging Activities		72
Stock Based Compensation		73
New Accounting Pronouncements Issued But Not Yet Adopted		73
Recently Adopted Accounting Pronouncements		73
Business		74
Overview		74
Business Strategies		75
Competitive Strengths		76
Our Relationship with Vinland		77
Natural Gas Prices		79
Natural Gas and Oil Data		80
Operations		83
Management		92
Our Board of Directors		92
Compensation Committee Interlocks and Insider Participation		94
Our Board of Directors and Executive Officers		94
Compensation Discussion and Analysis		96
Compensation Objectives		96
Compensation Committee		96
Elements of Compensation		96
Executive Compensation		97
Employment Agreements		97
Grants of Plan-Based Awards		98
Long-Term Incentive Plan		98
Class B Units		100
Potential Payments upon Termination or Change-in-Control		101
Compensation of Directors		103
Employee Benefits		103
Security Ownership of Certain Beneficial Owners and Management		104
Certain Relationships and Related Party Transactions		106
Management Services Agreement		106
Gathering and Compression Agreement		107
Operating Agreements		107
Registration Rights Agreement		108
Omnibus Agreement		109
Description of the Units		110
The Units		110
Transfer Agent and Registrar		110
Transfer of Units		110
The Limited Liability Company Agreement		111
Organization		111
Purpose		111
Fiduciary Duties		111
Agreement to be Bound by Limited Liability Company Agreement; Power of Attorney		112

Capital Contributions		112
Limited Liability		112
Voting Rights		113
Issuance of Additional Securities		113
Election of Members of Our Board of Directors		113
Removal of Members of Our Board of Directors		114
Amendment of Our Limited Liability Company Agreement		114
Merger, Sale or Other Disposition of Assets		115
Termination and Dissolution		116
Liquidation and Distribution of Proceeds		116
Limited Call Right		116
Meetings; Voting		117
Non-Citizen Assignees; Redemption		117
Indemnification		118
Books and Reports		118
Right To Inspect Our Books and Records		118
Registration Rights		119
Units Eligible for Future Sale		120
Material Tax Consequences		122
Partnership Status		123
Unitholder Status		124
Tax Consequences of Unit Ownership		124
Tax Treatment of Operations		130
Disposition of Units		134
Uniformity of Units		136
Tax-Exempt Organizations and Other Investors		137
Administrative Matters		138
State, Local and Other Tax Considerations		140
Investment in our Company by Employee Benefit Plans		141
Underwriting		142
Experts		145
Where You Can Find More Information		145
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

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

Assets
Current assets:
Cash	$	1,000
Total Assets	$	1,000
Members’ Equity
Members’ equity	$	1,000
Total Members’ Equity	$	1,000

	VANGUARD NATURAL RESOURCES, LLC
	By:	/s/ SCOTT W. SMITH
		Scott W. Smith
		President and Chief Executive Officer

	Name		Title		Date
/s/ SCOTT W. SMITH		President and Chief Executive		April 25, 2007
Scott W. Smith		Officer (Principal Executive Officer)
/s/ RICHARD A. ROBERT		Executive Vice President and		April 25, 2007
Richard A. Robert		Chief Financial Officer (Principal Financial Officer)
/s/ LASSE WAGENE		Director		April 25, 2007
Lasse Wagene
/s/ THOMAS M. BLAKE		Director		April 25, 2007
Thomas M. Blake
		Director		April 25, 2007
Michael J. Cannon