UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

Commission File Number 001-33756

Vanguard Natural Resources, LLC

(Exact Name of Registrant as Specified in Its Charter)

Telephone Number: (832) 327-2255

Internet Website: www.vnrllc.com

Securities registered pursuant to Section 12(b) of the Act:

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports),

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

The aggregate market value of Vanguard Natural Resources, LLC common units held by non-affiliates of the registrant as of March 12, 2008 was approximately $171,424,600 based upon the New York Stock Exchange composite transaction closing price.

As of March 12, 2008, 10,795,000 of the registrant’s common units remained outstanding.

Documents Incorporated by Reference:

Portions of the registrant’s proxy statement to be furnished to unitholders  in connection with its 2008 Annual Meeting of Unitholders are incorporated by reference in Part III, Items 10-14 of this annual report on Form 10-K for the year ending December 31, 2007 (“this Annual Report”).

Vanguard Natural Resources, LLC

TABLE OF CONTENTS

Forward Looking Statements

The statements contained in this report, other than statements of historical fact, constitute forward-looking statements. Such statements include, without limitation, all statements as to the production of oil and gas, product prices, oil and gas reserves, drilling and completion results, capital expenditures and other such matters. These statements relate to events and/or future financial performance and involve known and unknown risks, uncertainties and other factors that may cause our actual results, levels of activity, performance or achievements or the industry in which we operate to be materially different from any future results, levels of activity, performance or achievements expressed or implied by the forward-looking statements. These risks and other factors include those listed under Item 1A “Risk Factors” and those described elsewhere in this report.

In some cases, you can identify forward-looking statements by our use of terms such as “may,” “will,” “should,” “expects,” “plans,” “anticipates,” “believes,” “estimates,” “intends,” “predicts,” “potential,” or the negative of these terms or other comparable terminology. These statements are only predictions. Actual events or results may differ materially. In evaluating these statements, you should specifically consider various factors, including the risks outlined under “Risk Factors.” These factors may cause our actual results to differ materially from any forward-looking statement. Factors that could affect our actual results and could cause actual results to differ materially from those in forward-looking statements include, but are not limited to, the following:

·                  the volatility of realized natural gas and oil prices;

·                  the conditions of the capital markets, interest rates, availability of credit facilities to support business requirements, liquidity and general economic conditions;

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

·                  our business and financial strategy;

·                  our drilling locations;

·                  technology;

·                  our cash flow, liquidity and financial position;

·                  our production volumes;

·                  our operating expenses, general and administrative costs, and finding and development costs;

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

·                  our future operating results;

·                  our prospect development and property acquisitions;

·                  the marketing of oil and natural gas;

·                  competition in the oil and natural gas industry;

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

·                  governmental regulation of the oil and natural gas industry;

·                  environmental regulations;

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

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

Although we believe that the expectations reflected in the forward-looking statements are reasonable, we cannot guarantee future results, levels of activity, performance, or achievements. Moreover, neither we nor any other person assumes responsibility for the accuracy and completeness of these forward-looking statements. We do not intend to update any of the forward-looking statements after the date of this report to conform prior statements to actual results.

GLOSSARY OF TERMS

Below is a list of terms that are common to our industry and used throughout this document:

When we refer to natural gas and oil in “equivalents,” we are doing so to compare quantities of oil with quantities of natural gas or to express these different commodities in a common unit. In calculating equivalents, we use a generally recognized standard in which one Bbl of oil is equal to six Mcf of natural gas. Also, when we refer to cubic feet measurements, all measurements are at a pressure of 14.73 pounds per square inch.

PART I

ITEM 1.  BUSINESS

Overview

We are a publicly traded limited liability 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, and the Permian Basin, primarily in West Texas and Southeastern New Mexico.

We completed our initial public offering, or “IPO”, on October 29, 2007, and our common units, representing limited liability company interests, are listed on the NYSE Arca, Inc. under the symbol “VNR.”

On April 18, 2007 but effective January 5, 2007 our Predecessor was separated in the Restructuring into our operating subsidiary and Vinland Energy Eastern, LLC, an affiliate of Mr. Majeed S. Nami, who together with certain of his affiliates and related persons, is our largest unitholder. As part of the separation, we retained all of our Predecessor’s proved producing wells and associated reserves. We also retained 40% of our Predecessor’s working interest in the known producing horizons in approximately 95,000 gross undeveloped acres, which accounted for approximately 25% of our estimated proved reserves as of December 31, 2007, and a contract right to receive approximately 99% of the net proceeds from the sale of production from certain producing oil and gas wells, which accounted for approximately 4.5% of our estimated proved reserves as of December 31, 2007. In the separation, Vinland was conveyed the remaining 60% of our Predecessor’s working interest in the known producing horizons in this acreage, and 100% of our Predecessor’s working interest in depths above and 100 feet below our known producing horizons. Vinland acts as the operator of our existing wells in Appalachia and all of the wells that we drill in this area. The separation was effected to facilitate our formation, as we are a company focused on lower risk production, development and exploitation opportunities, while Vinland pursues higher capital intensive development, exploitation and exploration opportunities. Our working interest in any particular well in our drilling program will vary based on the lease or leases on which such well is located and the participation of any minority owners in the drilling of such wells.

On December 21, 2007, we entered in to a Purchase and Sale Agreement with the Apache Corporation for the purchase of certain oil and natural gas properties located in ten separate fields in the Permian Basin of West Texas and Southeastern New Mexico. The purchase price for said assets was $78.3 million with an effective date of October 1, 2007. We completed this acquisition on January 31, 2008 for an adjusted purchase price of $73.4 million, subject to customary post closing adjustments. In this purchase, we acquired working interests in 390 gross wells (67 net wells), 49 of which we operate. With respect to operations, we have established two district offices, one in Lovington, New Mexico and the other in Christoval, Texas to manage these assets. Our operating focus will be on maximizing existing production and looking for complementary acquisitions that we can add to this operating platform. With this acquisition, based on internal reserve estimates, we acquired 4.4 million barrels of oil equivalent, 83% of which is oil and 90% of which is proved developed producing. The current net production attributable to this purchase is approximately 800 barrels of oil equivalent per day and the reserves-to-production ratio is 15 years. With the closing of this acquisition, our daily production and total reserves increased approximately 40%. The effects of this acquisition are not reflected in the reserves, cash flows and other financial and operating information described below as of December 31, 2007 due to the acquisition closing on January 31, 2008.

At December 31, 2007, we owned working interests in 943 gross (825 net) productive wells and our average net production for the year ended December 31, 2007 was 11,610 Mcfe per day. We also have a 40% working interest in approximately 104,000 gross undeveloped acres surrounding or adjacent to our existing wells located in southeast Kentucky and northeast Tennessee. 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, 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 the operator of our existing wells and all of the wells that we will drill in Appalachia. Approximately 25%, or 16.3 Bcfe, of our estimated proved reserves as of December 31, 2007 were

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attributable to this 40% working interest. In addition, we own a contract right to receive approximately 99% of the net proceeds from the sale of production from certain oil and gas wells located in Bell and Knox Counties, Kentucky, which accounted for approximately 4.5% of our estimated proved reserves as of December 31, 2007. Our estimated proved reserves at December 31, 2007 were 67.1 Bcfe, of which approximately 97% were natural gas and 75% were classified as proved developed. Our properties, including our 40% working interest in approximately 104,000 gross undeveloped acres, fall within an approximate 750,000 acre area, which we refer to in this Annual Report 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 $5.0 million or less annually without a requirement to offer us the right to participate in such acquisitions.

Our average proved reserves-to-production ratio, or average reserve life, is approximately 16 years based on our proved reserves as of December 31, 2007 and our production for the year ended December 31, 2007. During 2007, we drilled 83 gross wells and as of December 31, 2007, we had identified 326 additional proved undeveloped drilling locations and over 217 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 in Appalachia and has the sole right to determine which wells are drilled in Appalachia 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. 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 four 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 three 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.

As used in this Annual Report on Form 10-K, unless we indicate otherwise: (1) “Vanguard Natural Resources, LLC,” “Vanguard,” “we,” “our,” “us” or like terms when used with respect to periods prior to completion of the separation of our operating company and Vinland, or the Restructuring, refer to our Predecessor and, when used with respect to periods after completion of the Restructuring, refer to Vanguard Natural Resources, LLC and its subsidiaries, (2) “Vinland” refers to Vinland Energy, LLC, a Delaware limited liability company that is affiliated with our largest unitholder, and its affiliates and subsidiaries, (3) “Nami” refers to Majeed S. Nami who owns a 90% interest in Vinland and, together with certain of his affiliates and related persons, owns approximately a 27.1% membership interest in us, and (4) “our operating company” or “our Predecessor” refers to Vanguard Natural Gas, LLC (formerly Nami Holding Company, LLC).

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:

·        In the Appalachian basin, 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;

·        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

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

Our Relationship with Vinland

General.   We believe that one of our principal strengths is our relationship with Vinland. Majeed S. Nami owns 90% of Vinland and Nami and certain of his affiliates and related persons own a 27.1% membership interest in us. 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 until the Restructuring, Vinland’s management team grew 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, 2007, Vinland operated substantially all of our wells in Appalachia. As of December 31, 2007 after giving effect to the Restructuring described in Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations–Restructuring Plan, Vinland had assets consisting of production from their 60% working interest in new wells drilled in 2007, a 60% working interest in approximately 95,000 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.

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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. Currently there is minimal production from 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 likely 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 that we have entered into with Vinland, Vinland provides us with a right of first offer with respect to the sale by Vinland of any of its natural gas and oil properties within our area of mutual interest. 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.

Participation Agreement. Pursuant to a participation agreement that we have entered into with Vinland, Vinland has general control over our drilling program in Appalachia and has 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 during such quarter, in which we will own a 100% working interest. 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 four 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 three years.

Operation and Development of Assets.   Effective as of January 5, 2007, we entered into various agreements with Vinland, under which we rely on Vinland to operate our existing producing wells in Appalachia and coordinate our development drilling program in Appalachia. We expect to benefit from the substantial development and operational expertise of Vinland’s management in the Appalachian Basin. Pursuant to the participation agreement that we have entered into with Vinland, Vinland has control over our drilling program in Appalachia and has the sole right to determine which wells are proposed to be drilled in Appalachia.

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.

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

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Vinland gathers 100% of our current production in Appalachia and we expect Vinland will gather 100% of the wells we expect to drill in Appalachia during 2008. 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.

We also assumed certain transportation agreements that Vinland had 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 $0.27 per MMBtu plus a fuel charge equal to 2% of volume for this transportation service.

In addition, we assumed a right to 7,000 MMBtu/day of firm transportation that Vinland had 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 was approximately 49% of our total 2007 actual production in Appalachia.

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.

Natural Gas and Oil 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, 2007, 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 $0.26 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. For the year ended December 31, 2007, our average realized natural gas prices (before hedging), represented a $1.29 per Mcfe premium to NYMEX natural gas prices, which accounts for both the basis differential and the Btu adjustments.

In the Permian Basin, most of our gas production is casinghead gas produced in conjunction with our oil production.  Casinghead gas typically has a high Btu content and requires processing prior to sale to third parties. We have a number of processing agreements in place with gatherers/processors of our casinghead gas and we share in the revenues associated with processing depending on the terms of the various agreements. We expect that the revenues from the sale of cashinghead gas plus our share of the revenues from the sale of natural gas liquids will result in a realized price per Mcf of gas produced equal to the NYMEX natural gas price.

Our oil production, both in Appalachia and the Permian Basin is sold under month to month sales contracts with purchasers that take delivery of the oil volumes at the tank batteries adjacent to the producing wells. Our pricing for oil sales is based on the monthly average of the West Texas Intermediate Price, or “WTI”, as posted for the various regions and published by Plains Marketing, LP, ConocoPhillips or a similar large purchaser of oil, less a transportation or quality differential which corresponds to the field location or type of oil being produced. In Appalachia, we have historically received the average WTI price less $8.00. In the Permian Basin, we expect to receive the average WTI price less $5.00.

We enter into derivative transactions in the form of hedging arrangements to reduce the impact of natural gas and oil price volatility on our cash flow from operations. Currently, we use fixed-price swaps and NYMEX collars and put options to hedge natural gas and oil prices. By removing the price volatility from a significant portion of our natural gas and oil production, we have mitigated, but not eliminated, the potential effects of fluctuation in natural gas and oil prices on our cash flow from operations. For a description of our derivative positions, please read “Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations—Cash Flow from Operations.”

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Natural Gas and Oil Data

Proved Reserves

The following table presents our estimated net proved natural gas and oil reserves and the present value of the estimated proved reserves at December 31, 2007, based on a reserve report prepared by Netherland, Sewell & Associates, Inc., or “NSAI”. The estimate of net proved reserves has not been filed with or included in reports to any federal authority or agency other than the Securities and Exchange Commission, or “SEC”,  in connection with this Annual Report. The Standardized Measure value shown in the table is not intended to represent the current market value of our estimated natural gas and oil reserves.

(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 period end are 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 “Item 1A—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 2007, we paid NSAI approximately $75,000 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:

(a)        Excludes premiums paid on settled derivatives.

(b)       Includes $2.1 million ($0.51/Mcfe) of non-cash compensation expense.

Productive Wells

The following table sets forth information at December 31, 2007 relating to the productive wells in Appalachia 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.

Developed and Undeveloped Acreage

The following table sets forth information as of December 31, 2007 relating to our leasehold acreage in Appalachia.

(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.

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(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 in Appalachia 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 in Appalachia takes 10 days to drill and is expected to have an average cost of $250,000 in 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.

In the Permian Basin acquisition, we acquired four development drilling locations that we intend to drill, at least two of which are planned to be drilled in 2008. These projected wells range in depth from 8,000 to 11,000 feet and target multiple producing horizons.  These wells are estimated to each cost between $0.7 million to $1.0 million to drill and complete, depending on the total depth targeted.

Since formation of our Predecessor in 1999, Vinland has drilled over 553 wells on our properties, substantially 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 2008 drilling program. In 2007, we drilled 83 gross wells. As of December 31, 2007, we had identified 326 additional proved undeveloped drilling locations and over 217 other drilling locations in this area. In 2008, we have budgeted $13.0 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 120 will be located in Kentucky and 10 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, 2007, 2006 and 2005. 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.

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Operations

General

Effective as of January 5, 2007, we entered into various agreements with Vinland, under which we rely on Vinland to operate our existing producing wells and coordinate our development drilling program in Appalachia. Pursuant to a participation agreement that we have entered into with Vinland, Vinland generally has control over our drilling program in Appalachia and has the sole right to determine which wells are drilled in Appalachia 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. 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 four 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 three 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.

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 Appalachia.

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Principal Customers

For the year ended December 31, 2007, 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 41%, 16%, 13%, 11% and 11%, respectively, of our total revenues. Our top five purchasers during the year ended December 31, 2007, therefore accounted for 92% 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. However, if we were to lose a customer, we believe we could identify a substitute purchaser in a timely manner.

Hedging Activities

We enter into hedging arrangements to reduce the impact of natural gas and oil price volatility on our cash flow from operations. Currently, we use a combination of fixed-price swaps and NYMEX collars and put options to hedge natural gas and oil prices. Our derivative contracts in place for periods subsequent to December 31, 2007 hedge our expected production as follows:

(1)          Ceiling price for 700,000 MMBtu of production from March to September 2008 is $9.00/MMBtu and for 300,000 MMBtu of production from October to December 2008 is $9.25/MMBtu.

We have also entered into interest rate swaps, which require payment to or from the counterparty based upon the differential between two rates for a predetermined contractual amount. This hedging activity converts a floating interest rate to a fixed interest rate and is intended to manage our exposure to interest rate fluctuations.

The following summarizes information concerning our positions in open interest rate swaps applicable to periods subsequent to December 31, 2007.

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, leasing acreage, contracting for drilling equipment and securing trained personnel. Many of these competitors have financial and technical resources and staff substantially larger than ours or a different business model. 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.

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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. Vinland diversifies suppliers to help manage such shortages.

Competition is also strong for attractive natural gas producing properties, undeveloped leases and drilling rights, and we cannot assure unitholders 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 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 and oil leases, we perform title reviews on the most significant leases and, depending on the materiality of properties, we may obtain a title opinion or review previously obtained title opinions. As a result, we have obtained title opinions on a significant portion of our natural gas and oil 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. Although title to these properties is subject to encumbrances in some cases, such as customary interests generally retained in connection with acquisition of real property, customary royalty interests, contract terms and restrictions, liens under operating agreements, liens related to environmental liabilities associated with historical operations, liens for taxes not yet payable and other burdens, restrictions and minor encumbrances customary in the oil and natural gas industry, we believe that none of these liens, restrictions, easements, burdens and encumbrances will materially detract from the value of these properties or from our interest in these properties, or will materially interfere with our use of these properties in the operation of our business.

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:

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·        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, 2007, we did not incur any material capital expenditures for installation of remediation or pollution control equipment at any of our facilities. As of the date of this Annual Report, we are not aware of any environmental issues or claims that will require material capital expenditures during 2008 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 our operations as well as the natural gas and oil exploration and production industry in general 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, as amended, 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. Our current exploitation and production activities, as well as proposed exploitation and development plans, on federal lands require governmental permits or similar authorizations 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, as amended, 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 of the RCRA, 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. 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, as amended, also known as “CERCLA”, or “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

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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, as amended, or “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 state waters as well as 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 in substantial compliance with the requirements of the Clean Water Act.

Air Emissions.   The Clean Air Act, as amended, 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, as amended, or “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 the applicable requirements of OSHA.

Global Warming and Climate Control.  In response to recent studies suggesting that emissions of certain gases, referred to as “greenhouse gases” and including carbon dioxide and methane, may be contributing to warming of the Earth’s atmosphere, the current session of the U.S. Congress is considering climate change-related legislation to restrict greenhouse gas emissions.  One bill recently approved by the U.S. Senate Environment and Public Works Committee, known as the Lieberman-Warner Climate Security Act or S.2191, would require a 70% reduction in emissions of greenhouse gases from sources within the United States between 2012 and 2050. The Lieberman-Warner bill proposes a “cap and trade” scheme of regulation of greenhouse gas emissions — a ban on emissions above a defined reducing annual cap. Covered parties will be authorized to emit greenhouse emissions through the acquisition and subsequent surrender of emission allowances that may be traded or acquired on the open market.  Debate and a possible vote on this bill by the full Senate are anticipated to occur before mid-year 2008. In addition, at least one-third of the states have already taken legal measures to reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Depending on the particular program, we could be required to purchase and surrender allowances, either for greenhouse gas emissions resulting from our operations or from combustion of fuels (e.g., natural gas or oil) we produce.

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Also, as a result of the U.S. Supreme Court’s decision on April 2, 2007 in Massachusetts, et al. v. EPA and certain provisions of the Clean Air Act, the EPA may regulate carbon dioxide and other greenhouse gas emissions from mobile sources such as cars and trucks, even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. The EPA has publicly stated its goal of issuing a proposed rule to address carbon dioxide and other greenhouse gas emissions from vehicles and automobile fuels but the timing for issuance of this proposed rule is unsettled as the agency reviews its mandates under the Energy Independence and Security Act of 2007, which includes expanding the use of renewable fuels and raising the corporate average fuel economy standards. The Court’s holding in the Massachusetts decision that greenhouse gases including carbon dioxide fall under the federal Clean Air Act’s definition of “air pollutant” may also result in future regulation of carbon dioxide and other greenhouse gas emissions from stationary sources under certain CAA programs. New federal or state laws requiring adoption of a stringent greenhouse gas control program or imposing restrictions on emissions of carbon dioxide in areas of the United States in which we conduct business could adversely affect our cost of doing business and demand for our natural gas and oil.

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. If in the future one or more of our facilities becomes subject to such legislation, then the cost to comply with such law 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:

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, or “FERC”.

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Federal and state regulations govern the price and terms for access to natural gas pipeline transportation. The FERC’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, or “EP Act 2005”. Among other matters, EP Act 2005 amends the Natural Gas Act, or “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 regulated by the FERC that violates the FERC’s rules. On January 19, 2006, the FERC issued rules implementing the provision of the EP Act of 2005. The rules make it unlawful 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 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. 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. While 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 and oil, including imposing severance taxes and requirements for obtaining drilling permits. For example, currently, a severance tax on natural gas and oil production is imposed at a rate of 4.5%, 3.0% and 3.75% in Kentucky, Tennessee and New Mexico, respectively. Texas currently imposes a 7.5% severance tax on gas production and 4.6% severance tax on oil production. 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 December 31, 2007, we had four full time employees. All of our employees work in our Houston office. Under the management services agreement with Vinland, we will rely on Vinland’s employees to operate our existing producing wells in Appalachia and coordinate our development drilling program in Appalachia. 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 lease agreement in January 2007 for approximately 2,320 square feet of office space in Houston, Texas. The lease for our Houston office expires in April 2010.

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ITEM 1A.   RISK FACTORS

Risks Related to Our Business

We may not have sufficient cash from operations to pay the quarterly distribution on our common units.

We may not have sufficient cash flow from operations each quarter to pay the 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 and future debt service requirements. 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:

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:

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. If we do not achieve our expected operational results or cannot borrow the amounts needed, we may not be able to pay the full, or any, amount of the quarterly distribution, in which event the market price of our common units may decline substantially.

We rely on Vinland, an affiliate of our largest unitholder, to execute our drilling program in Appalachia. 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.

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Effective as of January 5, 2007, we entered into various agreements with Vinland, an affiliate of our largest unitholder, under which we rely on Vinland to operate all of our existing producing wells and coordinate our development drilling program in Appalachia. For example, pursuant to a participation agreement that we have entered into with Vinland, Vinland generally has control over our drilling program in Appalachia and has 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 in Appalachia 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 in Appalachia 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 our unitholders.

Natural gas and oil prices are volatile. 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:

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, 2007, the closing price of a calendar month NYMEX natural gas price ranged from a high of $7.59 per MMBtu to a low of $5.84 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.

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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 our unitholders receive over the life of their investment will meet or exceed their initial capital investment.

Our acquisition activities will subject us to certain risks.

On December 21, 2007, we expanded our operations into the Permian Basin of West Texas and Southeastern New Mexico by entering into a Purchase and Sale Agreement with the Apache Corporation.  We spent approximately $78.3 million, after purchase price adjustments, on this acquisition. Any acquisition involves potential risks, including, among other things: the validity of our assumptions about reserves, future production, revenues and costs, including synergies; an inability to integrate successfully the businesses we acquire; a decrease in our liquidity by using a significant portion of our available cash or borrowing capacity to finance acquisitions; a significant increase in our interest expense or financial leverage if we incur additional debt to finance acquisitions; the assumption of unknown liabilities, losses or costs for which we are not indemnified or for which our indemnity is inadequate; the diversion of management’s attention to other business concerns; an inability to hire, train or retain qualified personnel to manage and operate our growing business and assets; the incurrence of other significant charges, such as impairment of other intangible assets, asset devaluation or restructuring charges; unforeseen difficulties encountered in operating in new geographic areas; an increase in our costs or a decrease in our revenues associated with any potential royalty owner or landowner claims or disputes; and customer or key employee losses at the acquired businesses.

Our decision to acquire a property will depend in part on the evaluation of data obtained from production reports and engineering studies, geophysical and geological analyses and seismic and other information, the results of which are often inconclusive and subject to various interpretations. Also, our reviews of acquired properties are inherently incomplete because it generally is not feasible to perform an in-depth review of the individual properties involved in each acquisition. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit us 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.

If our Permian Basin acquisition or other potential acquisitions do not generate increases in available cash per unit, our ability to make cash distributions to our unitholders could materially decrease.

Vinland controls our drilling program in Appalachia. Vinland has agreed to drill not less than 100 gross wells per calendar year for each of the next three years.

Pursuant to a participation agreement that we have entered into with Vinland, Vinland generally has control over our drilling program in Appalachia and has 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. 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.

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The participation agreement will remain in place for four 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 three years.

A substantial majority of our properties in the Permian Basin are operated by a third party.  Because we do not control the development of the properties we own but do not operate, we may not be able to achieve any production from these properties in a timely manner.

We currently only operate 49 of our 390 gross wells in the Permian Basin.  In addition, we expect that a substantial majority of future wells on our existing Permian Basin properties will be operated by third parties.  As a result, the success and timing of our drilling and development activities on such nonoperated properties depend upon a number of factors, including: 

·   the nature and timing of drilling and operational activities;

·   the timing and amount of capital expenditures;

·   the operators’ expertise and financial resources;

·   the approval of other participants in such properties; and

·   the selection of suitable technology.

If drilling and development activities are not conducted on these properties or are not conducted on a timely basis, we may be unable to increase our production or offset normal production declines, which may adversely affect our production, revenues and results of operations.

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. 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 operates all of our existing producing wells in Appalachia and coordinates our development drilling program in Appalachia. In addition, Vinland generally has control over our drilling program in Appalachia and has the sole right to determine which wells are drilled until January 1, 2011. In the event Vinland becomes insolvent or is declared bankrupt, we would have to become the operator of our wells in Appalachia 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 should, but 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.

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, the standardized measure of our proved reserves as of December 31, 2007 would decrease from $151.0 million to $120.0 million, based on price sensitivity generated from an internal evaluation. Our standardized measure is calculated using unhedged natural gas prices and is determined in accordance with the rules and regulations of the SEC. 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.

Additionally, the estimates of reserves for the properties we own in the Permian Basin are only internal estimates and have not been reviewed by our independent petroleum engineers and they may disagree with our estimates.

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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 unitholders.

Our operations require substantial capital expenditures, which will reduce our cash available for distribution. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a decline in our reserves and 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 and oil we are able to produce from existing wells;

·        the prices at which our natural gas and oil 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 and oil 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.

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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.

Effective as of January 5, 2007, we entered into a gathering and compression agreement with Vinland. Pursuant to this agreement, Vinland gathers, compresses, delivers and provides the services necessary for us to market our natural gas production in the area of mutual interest. Vinland delivers 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 and oil prices may not only decrease our revenues, but also reduce the amount of natural gas and oil 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, 2007, 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 41%, 16%, 13%, 11% and 11%, respectively, of our total revenues. Our top five purchasers during the year ended December 31, 2007, therefore accounted for 92% 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;

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

·        RCRA and comparable state laws that impose requirements for the handling and disposal of waste from our facilities; and

·        CERCLA 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 “Item 1—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 Annual Report.

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

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·        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, 2007, we had identified 326 proved undeveloped drilling locations and over 217 additional drilling locations in Appalachia. 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 217 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:

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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 and debt covenant violations.

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.

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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 90% 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 90% 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.

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 winter and 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 and oil price volatility on our cash flow from operations. Currently, we use a combination of fixed-price swaps and NYMEX collars and put options to hedge natural gas and oil prices. Please read “Item 1—Operations— Hedging Activities” and “Item 7A—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

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·      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 Restructuring has been involved in an ongoing dispute with Asher Land and Mineral Company, Ltd., or Asher, pursuant to which Asher claims that Nami Resources Company, LLC 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 Company, LLC a contract right to receive approximately 99% of the net proceeds, after deducting royalties paid to other parties, severance taxes, third-party transportation costs, costs incurred in the operation of wells and overhead costs, from the sale of production from certain producing oil and gas wells located within the Asher lease, which accounted for 4.5% of our proved reserves as of December 31, 2007. The Asher lease and the litigation related thereto were retained by Nami Resources Company, LLC. If the Asher lease is terminated or if Nami Resources Company, LLC 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, Richard A. Robert, our Executive Vice President and Chief Financial Officer and Britt Pence, our Vice President of Engineering. We maintain no key person insurance for either Mr. Smith, Mr. Robert or Mr. Pence. The loss of any or all of Messrs. Smith, Robert and Pence 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.

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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 and natural resource 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 “Item1—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.

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Risks Related to Our Structure

Mr. Nami, who together with certain of his affiliates and related persons, own approximately 27.1% of our outstanding common units, 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 our unitholders’ and may be to our detriment. Our limited liability company agreement limits the remedies available to our unitholders in the event  unitholders have a claim relating to conflicts of interest.

Two members of our board of directors are officers or directors or affiliates of Vinland, which is 90% 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:

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

We may issue additional units without unitholder approval, which would dilute their 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:

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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 unitholders to sell their 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, unitholders may be required to sell their units at an undesirable time or price and therefore may receive a lower or no return on their investment. Unitholders may also incur tax liability upon a sale of their units.

The price of our common units could be subject to wide fluctuations, unitholders could lose a significant part of their 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:

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.

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, or the “Delaware Act”, we may not make a distribution to unitholders 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.

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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

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 additional amounts of entity-level taxation for state tax purposes, taxes paid, if any, would reduce the amount of cash available for distribution to unitholders.

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.

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

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rates, currently at a maximum rate of 35%, and would likely pay state income tax at varying rates. Distributions to unitholders would generally be taxed again as corporate distributions, and no income, gain, loss, deduction or credit would flow through to unitholders. 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. At the federal level, legislation has been proposed that would eliminate partnership tax treatment for certain publicly traded LLCs.  Although such legislation would not apply to us as currently proposed, it could be amended prior to enactment in a manner that does apply to us.  We are unable to predict whether any of these changes or other proposals will ultimately be enacted.  Moreover, any modification to the federal income tax laws and interpretations thereof may or may not be applied retroactively.  Any such changes could negatively impact the value of an investment in our units.  At the state level, 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.   For example, we are required to pay Texas franchise tax at a maximum effective rate of 0.7% of our gross income apportioned to Texas in the prior year.  If any other state were to impose a tax upon us as an entity, the cash available for distribution to unitholders 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.

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The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of 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.

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

Because our unitholders will be treated as partners to whom we will allocate taxable income which could be different in amount than the cash we distribute, unitholders will be required to pay federal income taxes and, in some cases, state and local income taxes on their share of our taxable income, whether or not they receive cash distributions from us. Unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from their share of our taxable income.

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

If unitholders sell their common units, they will recognize a gain or loss equal to the difference between the amount realized and their tax basis in those common units. Because distributions in excess of a unitholder’s allocable share of our net taxable income decreases the tax basis in the unitholder’s common units, the amount, if any, of such prior excess distributions with respect to the units they sell will, in effect, become taxable income to them if they sell such units at a price greater than their tax basis in those units, even if the price they receive is less than their 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 a unitholders sells their units, they may incur a tax liability in excess of the amount of cash they receive from the sale.

Tax-exempt entities and non-U.S. 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 IRAs 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 non-U.S. person, you should consult your tax advisor before investing in our units.

We 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.

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

  We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury Regulations. If the IRS were to challenge this method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

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

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

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, which would result in us filing two tax returns (and our unitholders could receive two Schedules K-1) for one fiscal year and could result in a deferral of depreciation deductions allowable in computing our taxable income.  In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination.  Our termination currently would not affect our classification as a partnership for federal income tax purposes.  If treated as a new partnership, we must make new tax election and could be subject to penalties if we are unable to determine that a termination occurred.

As a result of investing in our common units, you may become subject to state and local taxes and return filing requirements in jurisdictions where we operate or own or acquire property.

In addition to federal income taxes, you will likely be subject to other taxes, including foreign, state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if you do not live in any of those jurisdictions.  You will likely be required to file foreign, state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions.  Further, you may be subject to penalties for failure to comply with those requirements.  We currently own property and conduct business in Kentucky, New Mexico, Tennessee and Texas.  Each of these states, other than Texas, imposes an income tax on individuals.  Most of these states also impose an income tax on corporations and other entities.  As we make acquisitions or expand our business, we may own assets or conduct business in additional states that impose a personal income tax.  It is your responsibility to file all United States federal, foreign, state and local tax returns.

ITEM 1B.     UNRESOLVED STAFF COMMENTS

None.

ITEM 2.     PROPERTIES

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

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

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ITEM 3.     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 Restructuring, has been involved in an ongoing dispute with Asher Land and Mineral Company, Ltd., or Asher, pursuant to which Asher claims that Nami Resources Company, LLC 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.

On August 29, 2007, Asher filed a motion to add additional defendants to the action cited above, including Vanguard Natural Resources, LLC. The Company has filed several motions to be dismissed from this action but to date is still a named defendant in this case. We have retained separate counsel to monitor this case as it progresses.

In connection with the Restructuring, we received a contract right to receive approximately 99% of the net proceeds from the sale of production from certain producing oil and gas wells located within the Asher lease, which accounted for approximately 4.5% of our estimated proved reserves as of December 31, 2007. We did not receive an assignment of any working interest in the Asher lease. The Asher lease and the litigation related thereto were retained by Nami Resources Company, LLC. If the Asher lease is terminated or if Nami Resources Company, LLC’  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 Restructuring, Nami Resources Company, LLC 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 Company, LLC and Vinland will remain in place until the resolution of the Asher litigation.

None.

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PART II

Our common units are traded on the NYSE Arca, Inc. under the symbol “VNR”. Our units began trading on October 24, 2007, in connection with our IPO. On March 12, 2008, there were 10,795,000 common units outstanding and approximately twelve unitholders, which does not include beneficial owners whose units are held by a clearing agency, such as a broker or a bank. On March 12, 2008, the market price for our common units was $15.88 per unit, resulting in an aggregate market value of units held by non-affiliates of approximately $171,424,600.  The following table presents the high and low sales price for our common units during the periods indicated.

Stock Performance Graph. The performance graph below compares total unitholder return on our units, with the total return of the Standard & Poor’s 500 Index, or “S&P 500 Index” and our Peer Group Index, a weighted composite of eight up-stream energy publicly traded partnerships. Total return includes the change in the market price, adjusted for reinvested dividends or distributions, for the period shown on the performance graph and assumes that $100 was invested in VNR at the last reported sale price of units as reported by NYSE Arca, Inc. ($18.94) on October 24, 2007 (the day trading of units commenced), and in the S&P 500 Index and our peer group index on the same date.  The results shown in the graph below are not necessarily indicative of future performance.

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Distributions Declared. The following table shows the amount per unit, record date and payment date of the quarterly cash distributions we paid on each of our common units for each period presented. Future distributions are at the discretion of our board of directors and will depend on business conditions, earnings, our cash requirements and other relevant factors.

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

(a)                     the sum of:

(b)                    less the amount of any cash reserves established by the board of directors (or our proportionate share of cash and cash equivalents in the case of subsidiaries that are not wholly owned) to:

provided that disbursements made by us or any of our subsidiaries or cash reserves established, increased or reduced after the end of a quarter but on or before the date of determination of available cash for that quarter shall be deemed to have been made, established, increased or reduced, for purposes of determining available cash, within that quarter if the board of directors so determines.

Use of Proceeds

Our IPO of common units representing limited liability company interests in us commenced on October 23, 2007. Our Registration Statement (File No. 333-142363) on Form S-1, as amended, was declared effective by the SEC on October 23, 2007. We completed our IPO of 5,250,000 common units representing limited liability company interests in us on October 29, 2007 at a price of $19.00 per unit ($17.741 per unit after the underwriting discount) for gross proceeds of $99,750,000 ($93,140,250 after underwriting discount).

The proceeds of our IPO were used to reduce indebtedness under our Credit Facility by $80.0 million and the balance was used for the payment of accrued distributions to pre-IPO unitholders and the payment of a deferred swap obligation.

All proceeds received from our IPO have been applied.

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ITEM 6.  SELECTED FINANCIAL DATA

Set forth below is our summary of our 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, 2003 and the balance sheet as of December 31, 2003 are derived from the unaudited financial statements of our Predecessor. Please read “Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations—Comparability of Financials Statements” for the reasons why the historical financial statements of our Predecessor included in this Annual Report on Form 10-K may not be comparable to our results of operations.

The selected financial data should be read together with Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations and Part II, Item 8, Financial Statements and Supplementary Data included in this Report on Form 10-K.

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.”

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