**UNITED STATES**

**SECURITIES AND EXCHANGE COMMISSION**

**Washington, D.C.20549**

 

**Form 10-K**
|            |       |                                                                                                   |
|-----------------|------------|--------------------------------------------------------------------------------------------------------|
| **(Mark  One)** | ** ** | ** **                                                                                             |
| **x**           | ** ** | **ANNUAL  REPORT PURSUANT TO SECTION 13 OR 15(d) OF****THE SECURITIES EXCHANGE ACT OF 1934** |
| ** **      | ** ** | ** **                                                                                             |
| ** **      | ** ** | **For  the fiscal year ended December 31, 2007**                                                  |

 
| ** ** | ** ** | **OR**                                                                                                                                                          |
|------------|------------|-----------------------------------------------------------------------------------------------------------------------------------------------------------------|
| ** ** | ** ** | ** **                                                                                                                                                      |
| **o**      | ** ** | **TRANSITION  REPORT PURSUANT TO SECTION 13 OR 15(d) OF****THE SECURITIES EXCHANGE ACT OF 1934**                                                      |
| ** ** | ** ** | ** **                                                                                                                                                      |
| ** ** | ** ** | **For  the transition period  from          to          .** |

 

**CommissionFile Number 001-33756**

 

**VanguardNatural Resources, LLC**

(Exact Name ofRegistrant as Specified in Its Charter)

 

| **Delaware**                                                  | ** ** | **61-1521161**                      |
|---------------------------------------------------------------|------------|-------------------------------------|
| (State or Other Jurisdiction ofIncorporation or Organization) |       | (I.R.S. EmployerIdentification No.) |
|                                                          |       |                                |
| **7700  San Felipe, Suite 485****Houston, Texas**        | ** ** | **77063**                           |
| (Address of Principal Executive Offices)                      |       | (Zip Code)                          |

 

**TelephoneNumber: (832) 327-2255**

**InternetWebsite: www.vnrllc.com**

**Securitiesregistered pursuant to Section 12(b) of the Act:**

 

| **Title of Each Class** | ** ** | **Name of Each Exchange  on which Registered** |
|-------------------------|------------|------------------------------------------------|
| ** **              | ** ** | ** **                                     |
| Common Units            |       | NYSE  Arca, Inc.                          |

 

**Securitiesregistered pursuant to Section 12(g) of the Act: None**

 

Indicate by checkmark if the registrant is a well-known seasoned issuer, as defined in Rule 405of the Securities Act.
|   |   | Yes o |   | No x |
|--------|--------|-------|--------|------|

 

Indicate by check mark ifthe registrant is not required to file reports pursuant to Section 13 or Section 15(d) ofthe Act.
|   |   | Yes o |   | No x |
|--------|--------|-------|--------|------|

 

Indicate by checkmark whether the registrant (1) has filed all reports required to be filedby Section 13 or 15(d) of the Securities Exchange Act of 1934 duringthe preceding 12 months (or for such shorter period that the registrantwas required to file such reports), 
| and (2) has been  subject to such filing requirements for the past 90 days. |   | Yes o |   | No x |
|---------------------------------------------------------------------------------------|--------|-------|--------|------|

 

Indicate by checkmark if disclosure of delinquent filers pursuant to Item 405 ofRegulation S-K is not contained herein, and will not be contained, to thebest of registrant’s knowledge, in definitive proxy or information statementsincorporated by reference in 
| Part III of this  Form 10-K or any amendment to this Form 10-K. |   |   |   | x   |
|--------------------------------------------------------------------------------|--------|--------|--------|---------------|

 

Indicate by check markwhether the registrant is a large accelerated filer, an accelerated filer, or anon-accelerated filer. See definition of “accelerated filer and largeaccelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):
|                                        |   |                      |
|---------------------------------------------|--------|---------------------------|
| Large accelerated filer o                   |   | Non-accelerated filer x   |
| Accelerated filer o                         |   | Smaller reporting company |
| (Do not check if smaller reporting company) |   |                      |

 

Indicate by checkmark whether the registrant is a shell company (as defined in Rule 12b-2of the Exchange Act).
|   |   | Yes o |   | No x |
|--------|--------|------------|--------|-----------|

 

The aggregate marketvalue of Vanguard Natural Resources, LLC common units held by non-affiliates ofthe registrant as of March 12, 2008 was approximately $171,424,600 basedupon 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.

 

**DocumentsIncorporated by Reference:**

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

 

** **

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**Vanguard Natural Resources, LLC**

 

**TABLEOF CONTENTS**

 
| ** **        | **Caption**                                                                                                        | ** ** | **Page** |
|-------------------|--------------------------------------------------------------------------------------------------------------------|------------|----------|
|              |                                                                                                               |       |
| Glossary of Terms |                                                                                                               |
|              | PART I                                                                                                        |       |
| Item 1.      | Business                                                                                                           | 1          |
| Item 1A.     | Risk Factors                                                                                                       | 15         |
| Item 1B.     | Unresolved  Staff Comments                                                                                         | 31         |
| Item 2.      | Properties                                                                                                         | 31         |
| Item 3.      | Legal Proceedings                                                                                                  | 32         |
| Item 4.      | Submission  of Matters to a Vote of Security Holders                                                               | 32         |
|              |                                                                                                               |       |
|              | PART II                                                                                                       |       |
| Item 5.      | Market for  Registrant’s Common Units, Related Stockholder Matters and Issuer Purchases  of Equity Securities | 33         |
| Item 6.      | Selected Financial  Data                                                                                           | 35         |
| Item 7.      | Management’s  Discussion and Analysis of Financial Condition and Results of Operations                        | 39         |
| Item 7A.     | Quantitative  and Qualitative Disclosures About Market Risk                                                        | 54         |
| Item 8.      | Financial  Statements and Supplementary Data                                                                       | 56         |
| Item 9.      | Changes in  and Disagreements with Accountants on Accounting and Financial Disclosure                              | 83         |
| Item 9A.     | Controls and Procedures                                                                                            | 83         |
| Item 9B.     | Other Information                                                                                                  | 83         |
|              |                                                                                                               |       |
|              | PART III                                                                                                      |       |
| Item 10.     | Directors,  Executive Officers and Corporate Governance                                                            | 84         |
| Item 11.     | Executive Compensation                                                                                             | 84         |
| Item 12.     | Security  Ownership of Certain Beneficial Owners and Management and Related Stockholder  Matters                   | 84         |
| Item 13.     | Certain  Relationships and Related Transactions, and Director Independence                                         | 84         |
| Item 14.     | Principal  Accountant Fees and Services                                                                            | 84         |
|              |                                                                                                               |       |
|              | PART IV                                                                                                       |       |
| Item 15.     | Exhibits and  Financial Statement Schedules                                                                        | 85         |
|              | Signatures                                                                                                         | 87         |

# ** **

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# **Forward Looking Statements**

# ** **

*The statements contained in thisreport, other than statements of historical fact, constitute forward-lookingstatements. Such statements include, without limitation, all statements as tothe production of oil and gas, product prices, oil and gas reserves, drillingand completion results, capital expenditures and other such matters. Thesestatements relate to events and/or future financial performance and involveknown and unknown risks, uncertainties and other factors that may cause ouractual results, levels of activity, performance or achievements or the industryin which we operate to be materially different from any future results, levelsof activity, performance or achievements expressed or implied by theforward-looking statements. These risks and other factors include those listedunder Item 1A “Risk Factors” and those described elsewhere in this report.*

 

*In some cases, you can identifyforward-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 differmaterially. In evaluating these statements, you should specifically considervarious factors, including the risks outlined under “Risk Factors.” Thesefactors may cause our actual results to differ materially from anyforward-looking statement. Factors that could affect our actual results andcould cause actual results to differ materially from those in forward-lookingstatements include, but are not limited to, the following:*

 

·                  the volatility of realized natural gas and oilprices;

 

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

 

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

 

·                  our business and financial strategy;

 

·                  our drilling locations;

 

·                  technology;

 

·                  our cash flow, liquidity and financialposition;

 

·                  our production volumes;

 

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

 

·                  the availability of drilling and productionequipment, labor and other services;

 

·                  our future operating results;

 

·                  our prospect development and propertyacquisitions;

 

·                  the marketing of oil and natural gas;

 

·                  competition in the oil and natural gasindustry;

 

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

 

·                  governmental regulation of the oil and naturalgas industry;

 

·                  environmental regulations;

 

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

 

·                  our strategic plans, objectives, expectationsand intentions for future operations.

 

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

 

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**GLOSSARY OF TERMS**

 

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

 
| /d     |   | = per day                         |   | MBtu   |   | = thousand British  thermal units                 |
|--------|--------|-----------------------------------|--------|--------|--------|---------------------------------------------------|
|   |   |                              |   |   |   |                                              |
| Bbls   |   | = barrels                         |   | Mcf    |   | = thousand cubic feet                             |
|   |   |                              |   |   |   |                                              |
| BBtu   |   | = billion British  thermal units  |   | Mcfe   |   | = thousand cubic feet  of natural gas equivalents |
|   |   |                              |   |   |   |                                              |
| Bcf    |   | = billion cubic feet              |   | MMBbls |   | = million barrels                                 |
|   |   |                              |   |   |   |                                              |
| Bcfe   |   | = billion cubic feet  equivalents |   | MMBtu  |   | = million British  thermal units                  |
|   |   |                              |   |   |   |                                              |
| Btu    |   | = British thermal unit            |   | MMcf   |   | = million cubic feet                              |
|   |   |                              |   |   |   |                                              |
| MBbls  |   | = thousand barrels                |   | MMcfe  |   | = million cubic feet of  natural gas equivalents  |

 

When we refer to naturalgas and oil in “equivalents,” we are doing so to compare quantities of oil withquantities of natural gas or to express these different commodities in a commonunit. In calculating equivalents, we use a generally recognized standard inwhich one Bbl of oil is equal to six Mcf of natural gas. Also, when we refer tocubic feet measurements, all measurements are at a pressure of 14.73 pounds persquare inch.

 

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**PART I**

 

**ITEM1.  BUSINESS**

 

**Overview**

 

We are a publicly tradedlimited liability company focused on the acquisition, development andexploitation of mature, long-lived natural gas and oil properties. Our primarybusiness objective is to generate stable cash flows allowing us to makequarterly cash distributions to our unitholders, and over time to increase ourquarterly cash distributions. Our properties are located in the southernportion of the Appalachian Basin, primarily in southeast Kentucky and northeastTennessee, and the Permian Basin, primarily in West Texas and Southeastern NewMexico.

 

We completed our initialpublic 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, 2007but effective January 5, 2007 our Predecessor was separated in theRestructuring into our operating subsidiary and Vinland Energy Eastern, LLC, anaffiliate of Mr. Majeed S. Nami, who together with certain of his affiliatesand related persons, is our largest unitholder. As part of the separation, weretained all of our Predecessor’s proved producing wells and associatedreserves. We also retained 40% of our Predecessor’s working interest in theknown producing horizons in approximately 95,000 gross undeveloped acres, whichaccounted for approximately 25% of our estimated proved reserves as of December 31,2007, and a contract right to receive approximately 99% of the net proceedsfrom the sale of production from certain producing oil and gas wells, whichaccounted for approximately 4.5% of our estimated proved reserves as of December 31,2007. In the separation, Vinland was conveyed the remaining 60% of ourPredecessor’s working interest in the known producing horizons in this acreage,and 100% of our Predecessor’s working interest in depths above and 100 feetbelow our known producing horizons. Vinland acts as the operator of ourexisting 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 companyfocused on lower risk production, development and exploitation opportunities,while Vinland pursues higher capital intensive development, exploitation andexploration opportunities. Our working interest in any particular well in ourdrilling program will vary based on the lease or leases on which such well islocated and the participation of any minority owners in the drilling of suchwells.

 

On December 21,2007, we entered in to a Purchase and Sale Agreement with the ApacheCorporation for the purchase of certain oil and natural gas properties locatedin ten separate fields in the Permian Basin of West Texas and Southeastern NewMexico. The purchase price for said assets was $78.3 million with an effectivedate of October 1, 2007. We completed this acquisition on January 31,2008 for an adjusted purchase price of $73.4 million, subject to customary postclosing adjustments. In this purchase, we acquired working interests in 390gross 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 theother in Christoval, Texas to manage these assets. Our operating focus will beon maximizing existing production and looking for complementary acquisitionsthat we can add to this operating platform. With this acquisition, based oninternal 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 currentnet production attributable to this purchase is approximately 800 barrels ofoil equivalent per day and the reserves-to-production ratio is 15 years. Withthe closing of this acquisition, our daily production and total reserves increasedapproximately 40%. The effects of this acquisition are not reflected in thereserves, cash flows and other financial and operating information describedbelow 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 ouraverage net production for the year ended December 31, 2007 was 11,610Mcfe per day. We also have a 40% working interest in approximately 104,000gross undeveloped acres surrounding or adjacent to our existing wells locatedin southeast Kentucky and northeast Tennessee. Vinland, an independent energycompany that was formed by our Predecessor in connection with the separation ofour Predecessor into our operating subsidiary and Vinland, owns the remaining60% working interest in this acreage, as well as a 100% working interest indepths above and 100 feet below our known producing horizons and is theoperator 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 

 

1

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attributable to this 40%working interest. In addition, we own a contract right to receive approximately99% of the net proceeds from the sale of production from certain oil and gaswells located in Bell and Knox Counties, Kentucky, which accounted forapproximately 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 proveddeveloped. Our properties, including our 40% working interest in approximately104,000 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,” orAMI. We have agreed with Vinland until January 1, 2012 to offer the otherthe right to participate in any acquisition, exploitation and developmentopportunities that arise in the AMI, subject however to Vinland’s right toconsummate up to two acquisitions with a purchase price of $5.0 million or lessannually without a requirement to offer us the right to participate in suchacquisitions.

 

Our average proved reserves-to-productionratio, or average reserve life, is approximately 16 years based on our provedreserves 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 over217 other drilling locations on our leasehold acreage. Pursuant to aparticipation agreement that we have entered into with Vinland, Vinlandgenerally has control over our drilling program in Appalachia and has the soleright to determine which wells are drilled in Appalachia until January 1,2011. During this period, we will meet with Vinland on a quarterly basis toreview Vinland’s proposal to drill not less than 25 nor more than 40 grosswells, 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 drilledin the subsequent quarter, provided that Vinland is required to drill at least100 gross wells per calendar year. If Vinland proposes the drilling of lessthan 25 gross wells in any quarter, we have the right to propose the drillingof 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 thedrilling of the proposed wells or future operations with respect to drilledwells, such party forfeits all right, title and interest in the natural gas andoil production that may be produced from such wells. The participationagreement will remain in place for four years and shall continue thereafter ona year to year basis until such time as either party elects to terminate theagreement. The obligations of the parties with respect to the drilling program describedabove will expire in three years, after which we each will have the right topropose the drilling of wells within the AMI and offer participation in suchproposed drilling to the other party and if either party elects not toparticipate in such proposed drilling or future operations with respect todrilled wells, such party forfeits all right, title and interest in the naturalgas and oil production that may be produced from such wells.

 

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

 

**Business Strategies**

 

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

 

·        In the Appalachian basin,work with Vinland to operate our producing properties and maintain productionthrough the development of our large existing leasehold within our area ofmutual interest;

 

·        Makeaccretive acquisitions of natural gas and oil properties in the known producingbasins of the continental United States characterized by a high percentage ofproducing reserves, long-lived, stable production and step-out developmentopportunities;

 

·    Maintaina conservative capital structure to ensure financial flexibility foropportunistic acquisitions; and

 

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·    Hedgeto reduce the volatility in our revenues resulting from changes in natural gasand oil prices.

 

**Our Relationship with Vinland**

 

*General.  *We believe that one of our principal strengths is our relationship withVinland. Majeed S. Nami owns 90% of Vinland and Nami and certain of hisaffiliates and related persons own a 27.1% membership interest in us. Vinland’ssenior management team has an average of approximately 25 years of experienceoperating in the Appalachian Basin and has operated our assets on behalf of ourPredecessor in southeast Kentucky and northeast Tennessee since 1999. Since itsformation in 1999 through the acquisition of producing properties from AmericanResources until the Restructuring, Vinland’s management team grew ourPredecessor through the drilling and completion of over 470 gross productivewells as well as through the acquisition of various producing properties. From2004 through December 31, 2006, our Predecessor added an estimated 21.4Bcfe 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, Item7, Management’s Discussion and Analysis of Financial Condition and Results ofOperations–Restructuring Plan, Vinland had assets consisting of production fromtheir 60% working interest in new wells drilled in 2007, a 60% working interestin approximately 95,000 gross undeveloped acres in the AMI, interests in anadditional 125,000 undeveloped acres and certain coalbed methane gas rightslocated in the Appalachian Basin, the rights to any natural gas and oil locatedon our acreage at depths above and 100 feet below our known producing horizonsand certain gathering and compression assets. Vinland intends to rely oncontributions from Nami to fund its proportionate share of our drilling programbut Nami has no obligation to make such contributions to Vinland.

 

3

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*Acquisitionof Assets.  * A principal component of our businessstrategy is to grow our asset base and production through the accretive acquisitionsof natural gas and oil properties characterized by long-lived, stableproduction. Vinland’s business strategy is to develop and divest natural gasand oil properties, generally every 12 to 24 months. Vinland’s management teamhas a track record of acquiring developed and undeveloped natural gas and oilproperties in the Appalachian Basin. Vinland is currently undertaking severalother natural gas and oil exploration and production projects in Appalachiawithin and outside of the AMI that are targeting both conventional andunconventional natural gas and oil reserves, including coalbed methane gas.Currently there is minimal production from these projects and all of theseprojects are outside of the AMI with Vinland. As Vinland develops these projectsto the point of commercial production, and potentially other undevelopedproperties that it may acquire in the future, it is likely these propertieswill have characteristics of properties suitable for us and our businessstrategies. We believe that the complementary nature of Vinland’s and ourbusiness strategies, the proximity of our respective asset bases, Nami’ssignificant equity interest in us and our right to make a first offer on futuresales by Vinland of properties located within our area of mutual interest willprovide us with a number of acquisition opportunities from Vinland in thefuture. Pursuant to the participation agreement that we have entered into withVinland, Vinland provides us with a right of first offer with respect to thesale by Vinland of any of its natural gas and oil properties within our area ofmutual interest. However, Vinland has no obligation or commitment to sell anysuch properties to us, and can be expected to act in a manner that isbeneficial to its interests.

 

### ***Participation Agreement.***Pursuantto a participation agreement that we have entered into with Vinland, Vinlandhas general control over our drilling program in Appalachia and has the soleright to determine which wells are drilled until January 1, 2011. During thisperiod, we will meet with Vinland on a quarterly basis to review Vinland’sproposal to drill not less than 25 nor more than 40 gross wells, in which wewill own a 40% working interest, in any quarter. Up to 20% of the proposedwells may be carried over and added to the wells to be drilled in thesubsequent quarter, provided that Vinland is required to drill at least 100gross wells per calendar year. If Vinland proposes the drilling of less than 25gross wells in any quarter, we have the right to propose the drilling of up toa 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 ofthe proposed wells or future operations with respect to drilled wells, such partyforfeits all right, title and interest in the natural gas and oil productionthat may be produced from such wells. The participation agreement will remainin place for four years and shall continue thereafter on a year to year basisuntil such time as either party elects to terminate the agreement. Theobligations of the parties with respect to the drilling program described abovewill expire in three years.

### ** **

*Operationand Development of Assets.  * Effective as of January 5,2007, we entered into various agreements with Vinland, under which we rely onVinland to operate our existing producing wells in Appalachia and coordinateour development drilling program in Appalachia. We expect to benefit from thesubstantial development and operational expertise of Vinland’s management inthe Appalachian Basin. Pursuant to the participation agreement that we haveentered into with Vinland, Vinland has control over our drilling program inAppalachia and has the sole right to determine which wells are proposed to bedrilled in Appalachia.

 

Under a managementservices agreement, Vinland will advise and consult with us regarding allaspects of our production and development operations and provide us withadministrative support services as necessary for the operation of our business.Vinland may, but does not have any obligation to, provide us with acquisitionservices under the management services agreement. While Vinland is notobligated to provide us with acquisition services, we expect that our mutuallybeneficial relationship will provide them with an incentive to grow ourbusiness by helping us to identify, evaluate and complete acquisitions thatwill be accretive to our distributable cash.

 

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

 

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Vinland gathers 100% ofour current production in Appalachia and we expect Vinland will gather 100% ofthe wells we expect to drill in Appalachia during 2008. Vinland’s network ofnatural gas gathering systems permits us to transport production from our wellswith fewer interruptions and also minimizes any delays associated with anon-affiliated gathering company extending its lines to our wells. We expectthat our relationship with Vinland will enable us to realize:

 

·    fasterconnection of newly drilled wells to the gathering system;

 

·    controlcompression costs and fuel use;

 

·    controlthe monthly nominations on the receiving pipelines to prevent imbalances andpenalties; and

 

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

 

We also assumed certaintransportation agreements that Vinland had with Delta Natural Gas with respectto volumes of gas produced in Kentucky. Delta receives gas from variousinterconnects with Vinland and redelivers said volumes to Columbia GasTransmission. We currently pay Delta $0.27 per MMBtu plus a fuel charge equalto 2% of volume for this transportation service.

 

In addition, we assumed aright to 7,000 MMBtu/day of firm transportation that Vinland had on theColumbia Gas Transmission system. We currently pay Columbia Gas $0.22 per MMBtuplus a fuel charge equal to 2% of volume for this firm transportation right.This volume was approximately 49% of our total 2007 actual production inAppalachia.

 

While our relationshipwith Vinland is a significant strength, it is also a source of potentialconflicts. For example, neither Vinland, nor any of its affiliates, isrestricted from competing with us. Vinland or its affiliates may acquire orinvest in natural gas and oil properties or other assets outside of the area ofmutual interest in the future without any obligation to offer us theopportunity to purchase or own interests in those assets. For example, Vinlandis currently undertaking several other natural gas and oil exploration andproduction projects in Appalachia within and outside of the AMI that aretargeting both conventional and unconventional natural gas and oil reserves,including coalbed methane gas.

 

**Natural Gas and Oil Prices**

 

The Appalachian Basin isa mature producing region with well known geologic characteristics. Reserves inthe Appalachian Basin typically have a high degree of step-out developmentsuccess; that is, as development progresses, reserves from newly completedwells are reclassified from the proved undeveloped to the proved developedcategory and additional adjacent locations are added to proved undevelopedreserves. As a result, the cumulative amount of total proved reserves tends toincrease as development progresses. Wells in the Appalachian Basin generallyproduce little or no water, contributing to a low cost of operation. Inaddition, most wells produce dry natural gas, which does not requireprocessing. Natural gas produced in the Appalachian Basin typically sells for apremium to New York Mercantile Exchange, or “NYMEX”, natural gas prices due tothe proximity to major consuming markets in the northeastern United States. Forthe year ended December 31, 2007, the average premium over NYMEX fornatural gas delivered to our primary delivery points in the Appalachian Basinon the Columbia Gas Transmission system was $0.26 per MMBtu. In addition, mostof our natural gas production has historically had a high Btu content,resulting in an additional premium to NYMEX natural gas prices. For the yearended December 31, 2007, our average realized natural gas prices (beforehedging), 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 ouroil production.  Casinghead gas typicallyhas 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 ofour casinghead gas and we share in the revenues associated with processingdepending on the terms of the various agreements. We expect that the revenuesfrom the sale of cashinghead gas plus our share of the revenues from the saleof natural gas liquids will result in a realized price per Mcf of gas producedequal to the NYMEX natural gas price. 

 

Our oil production, bothin Appalachia and the Permian Basin is sold under month to month salescontracts with purchasers that take delivery of the oil volumes at the tankbatteries adjacent to the producing wells. Our pricing for oil sales is basedon the monthly average of the West Texas Intermediate Price, or “WTI”, asposted for the various regions and published by Plains Marketing, LP,ConocoPhillips or a similar large purchaser of oil, less a transportation orquality differential which corresponds to the field location or type of oilbeing produced. In Appalachia, we have historically received the average WTIprice less $8.00. In the Permian Basin, we expect to receive the average WTIprice less $5.00.

 

We enter into derivativetransactions in the form of hedging arrangements to reduce the impact ofnatural gas and oil price volatility on our cash flow from operations.Currently, we use fixed-price swaps and NYMEX collars and put options to hedgenatural gas and oil prices. By removing the price volatility from a significantportion of our natural gas and oil production, we have mitigated, but noteliminated, the potential effects of fluctuation in natural gas and oil priceson our cash flow from operations. For a description of our derivativepositions, please read “Item 7—Management’s Discussion and Analysis ofFinancial Condition and Results of Operations—Cash Flow from Operations.”

 

5

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**Natural Gas and Oil Data**

 

***Proved Reserves***

 

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

 

| ** **                                               | ** ** | **As of   December 31,  2007** | ** ** |
|----------------------------------------------------------|------------|--------------------------------|------------|
| **Reserve Data:**                                        | ** ** | ** **                     | ** ** |
| Estimated net proved reserves:                           |       |                           |       |
| Natural gas  (Bcf)                                       |       | 65.1                           |       |
| Crude oil  (MBbls)                                       |       | 336                            |       |
| Total (Bcfe)                                             |       | 67.1                           |       |
| Proved developed (Bcfe)                                  |       | 50.3                           |       |
| Proved undeveloped (Bcfe)                                |       | 16.8                           |       |
| Proved developed reserves as % of total proved  reserves |       | 75                             | %          |
| **Standardized measure (in millions)(1)**                |       | $                              | 151.0      |   |
| **Representative Natural Gas and Oil Prices(2):**        | ** ** | ** **                     | ** ** |
| Natural gas—Spot  Henry Hub per MMBtu               |       | $                              | 6.79       |   |
| Oil—Spot WTI per  Bbl                               |       | $                              | 92.50      |   |

 

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

 

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

 

Proveddeveloped reserves are reserves that can be expected to be recovered throughexisting wells with existing equipment and operating methods. Provedundeveloped reserves are proved reserves that are expected to be recovered fromnew wells drilled to known reservoirs on undrilled acreage for which theexistence and recoverability of such reserves can be estimated with reasonablecertainty, or from existing wells on which a relatively major expenditure isrequired to establish production.

 

The data inthe above table represents estimates only. Natural gas and oil reserveengineering is inherently a subjective process of estimating undergroundaccumulations of natural gas and oil that cannot be measured exactly. Theaccuracy of any reserve estimate is a function of the quality of available dataand engineering and geological interpretation and judgment. Accordingly,reserve estimates may vary from the quantities of natural gas and oil that areultimately recovered. Please read “Item 1A—Risk Factors.”

 

Future pricesreceived for production and costs may vary, perhaps significantly, from theprices and costs assumed for purposes of these estimates. The standardizedmeasure shown should not be construed as the current market value of thereserves. The 10% discount factor used to calculate present value, which isrequired by Financial Accounting Standard Board pronouncements, is notnecessarily the most appropriate discount rate. The present value, no matterwhat discount rate is used, is materially affected by assumptions as to timingof future production, which may prove to be inaccurate.

 

From time totime, we engage NSAI to prepare a reserve and economic evaluation of propertiesthat we are considering purchasing. Neither NSAI nor any of their respectiveemployees has any interest in those properties and the compensation for theseengagements is not contingent on their estimates of reserves and future netrevenues for the subject properties. During 2007, we paid NSAI approximately $75,000for all reserve and economic evaluations.

 

***Production and Price History***

 

The following table setsforth information regarding net production of natural gas and oil and certainprice and cost information for each of the periods indicated:

 
| ** **                                            | ** ** | **Year Ended December 31,** | ** ** |
|-------------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                            | ** ** | **Vanguard**                               | ** ** | **Vanguard  Predecessor** | ** ** |
| ** **                                            | ** ** | **2007**                                   | ** ** | **2006** | ** ** | **2005** | ** ** |
| **Net  Production:**                                  |       |                                       |       |   |   |   |   |
| Total realized  production (MMcfe)                    |       | 4,238                                      |       | 4,378 |   | 3,894 |   |
| Average daily  production (Mcfe/d)                    |       | 11,610                                     |       | 11,995 |   | 10,669 |   |
| **Average  Realized Sales Prices ($ per Mcfe):** |       |                                       |       |   |   |   |   |
| Average sales  prices (including hedges)              |       | $                                          | 8.99       | (a) | $ | 8.22 |   | $ | 7.77 |   |
| Average sales  prices (excluding hedges)              |       | $                                          | 8.15       |   | $ | 8.72 |   | $ | 10.35 |   |
| **Average  Unit Costs ($ per Mcfe):**            |       |                                       |       |   |   |   |   |
| Production costs                                      |       | $                                          | 1.68       |   | $ | 1.52 |   | $ | 1.50 |   |
| Selling, general  and administrative expenses         |       | $                                          | 0.83       | (b) | $ | 1.19 |   | $ | 1.53 |   |
| Depreciation,  depletion and amortization             |       | $                                          | 2.12       |   | $ | 1.97 |   | $ | 1.59 |   |

 

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(a)        Excludes premiums paid on settled derivatives.

 

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

 

***Productive Wells***

 

The following table setsforth information at December 31, 2007 relating to the productive wells inAppalachia in which we owned a working interest as of that date. Productivewells consist of producing wells and wells capable of production, includingnatural gas wells awaiting pipeline connections to commence deliveries and oilwells awaiting connection to production facilities. Gross wells are the totalnumber of producing wells in which we have an interest, and net wells are thesum of our fractional working interests owned in gross wells.

 
| ** **   | ** ** | **Natural  Gas Wells** | ** ** |
|--------------|------------|-----------------------------|------------|
| ** **   | ** ** | **Gross**                   | ** ** | **Net** | ** ** |
| Operated     |       | —                      |       | — |   |
| Non-operated |       | 943                         |       | 825 |   |
| Total        |       | 943                         |       | 825 |   |

 

***Developed and Undeveloped Acreage***

 

The following table setsforth information as of December 31, 2007 relating to our leaseholdacreage in Appalachia.

 

| ** **   | ** ** | **Developed Acreage(1)** | ** ** | **Undeveloped  Acreage(2)** | ** ** | **Total Acreage** | ** ** |
|--------------|------------|-------------------------------|------------|-----------------------------|------------|------------------------|------------|
| ** **   | ** ** | **Gross(3)**                  | ** ** | **Net(4)**                  | ** ** | **Gross(3)**           | ** ** | **Net(4)** | ** ** | **Gross** | ** ** | **Net** | ** ** |
| Operated     |       | —                        |       | —                      |       | —                 |       | — |   | — |   | — |   |
| Non-operated |       | 18,900                        |       | 17,904                      |       | 103,861                |       | 43,704 |   | 122,761 |   | 61,608 |   |

 

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(1)   Developed acres are acres spaced or assignedto productive wells.

 

(2)   Undeveloped acres are acres on which wellshave not been drilled or completed to a point that would permit the productionof commercial quantities of natural gas or oil, regardless of whether suchacreage contains proved reserves.

 

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

 

6

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

 

***Drilling Activity***

 

Most of our wells inAppalachia are relatively shallow, ranging from 2,500 to 5,500 feet, and drillthrough as many as ten potential producing zones. Many of our wells arecompleted to multiple producing zones and production from these zones may becommingled. Our average well in Appalachia takes 10 days to drill and isexpected to have an average cost of $250,000 in 2008. Most of our wells areproducing and connected to a pipeline within 30 days after completion. Ingeneral, our producing wells have stable production profiles and long-livedproduction, often with total projected economic lives in excess of 50 years.Once drilled and completed, operating and maintenance requirements forproducing wells in the Appalachian Basin are generally low and only minimal, ifany, capital expenditures are required.

 

In the Permian Basinacquisition, we acquired four development drilling locations that we intend todrill, at least two of which are planned to be drilled in 2008. These projectedwells range in depth from 8,000 to 11,000 feet and target multiple producinghorizons.  These wells are estimated toeach cost between $0.7 million to $1.0 million to drill and complete, dependingon the total depth targeted.

 

Since formation of ourPredecessor in 1999, Vinland has drilled over 553 wells on our properties,substantially all of which were completed and placed on production. As theoperator of our properties, Vinland currently utilizes three drilling rigs thatare under contract for our 2008 drilling program. In 2007, we drilled 83 grosswells. As of December 31, 2007, we had identified 326 additional provedundeveloped drilling locations and over 217 other drilling locations in thisarea. In 2008, we have budgeted $13.0 million for the participation of thedrilling of approximately 130 gross wells (52 net wells), all of which will beoperated by Vinland. Of those 130 wells, we estimate that 120 will be locatedin Kentucky and 10 will be located in Tennessee. As successful developmentwells in the Appalachian Basin frequently result in the reclassification ofadjacent lease acreage from unproved to proved, we expect that a significantnumber of our unproved drilling locations will be reclassified as proveddrilling locations prior to the actual drilling of these locations.

 

We intend to concentrateour drilling activity on lower risk, development properties. The number andtypes of wells we drill will vary depending on the amount of funds we haveavailable for drilling, the cost of each well, the size of the fractionalworking interests we acquire in each well and the estimated recoverablereserves attributable to each well.

 

The following table setsforth information with respect to wells completed during the years ended December 31,2007, 2006 and 2005. The information should not be considered indicative offuture performance, nor should it be assumed that there is necessarily anycorrelation between the number of productive wells drilled, quantities ofreserves found or economic value. Productive wells are those that producecommercial quantities of natural gas, regardless of whether they produce areasonable rate of return.

 

| ** **                  | ** ** | **Year Ended December 31,** | ** ** |
|-----------------------------|------------|--------------------------------------------|------------|
| ** **                  | ** ** | **Vanguard**                               | ** ** | **Vanguard  Predecessor** | ** ** |
| ** **                  | ** ** | **2007**                                   | ** ** | **2006** | ** ** | **2005** | ** ** |
| **Gross  wells:**           |       |                                       |       |   |   |   |   |
| Productive                  |       | 82                                         |       | 100 |   | 120 |   |
| Dry                         |       | 1                                          |       | — |   | — |   |
| Total                       |       | 83                                         |       | 100 |   | 120 |   |
| **Net  Development wells:** |       |                                       |       |   |   |   |   |
| Productive                  |       | 33                                         |       | 96 |   | 111 |   |
| Dry                         |       | —                                     |       | — |   | — |   |
| Total                       |       | 33                                         |       | 96 |   | 111 |   |
| **Net  Exploratory wells:** |       |                                       |       |   |   |   |   |
| Productive                  |       | —                                     |       | 4 |   | 9 |   |
| Dry                         |       | —                                     |       | — |   | — |   |
| Total                       |       | —                                     |       | 4 |   | 9 |   |

 

7

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**Operations**

 

***General***

 

Effective as of January 5,2007, we entered into various agreements with Vinland, under which we rely onVinland to operate our existing producing wells and coordinate our developmentdrilling program in Appalachia. Pursuant to a participation agreement that wehave entered into with Vinland, Vinland generally has control over our drillingprogram in Appalachia and has the sole right to determine which wells aredrilled in Appalachia until January 1, 2011. During this period, we willmeet with Vinland on a quarterly basis to review Vinland’s proposal to drillnot 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 becarried 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 percalendar year. If Vinland proposes the drilling of less than 25 gross wells inany quarter, we have the right to propose the drilling of up to a total of 14net wells, in which we will own a 100% working interest, in a given quarterlyperiod. If Vinland drills its minimum commitment during the four year period, wedo not have the ability to drill our own additional wells in the AMI. If eitherparty elects not to participate in the drilling of the proposed wells or futureoperations with respect to drilled wells, such party forfeits all right, titleand interest in the natural gas and oil production that may be produced fromsuch wells. The participation agreement will remain in place for four years andshall continue thereafter on a year to year basis until such time as eitherparty elects to terminate the agreement. The obligations of the parties withrespect 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 withinthe AMI and offer participation in such proposed drilling to the other partyand if either party elects not to participate in such proposed drilling orfuture operations with respect to drilled wells, such party forfeits all right,title and interest in the natural gas and oil production that may be producedfrom such wells.

 

Under a managementservices agreement, Vinland will advise and consult with us regarding allaspects of our production and development operations, and provide us withadministrative support services as necessary for the operation of our businessin 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 EnergyPartners, LLC accounted for approximately 41%, 16%, 13%, 11% and 11%,respectively, of our total revenues. Our top five purchasers during the yearended December 31, 2007, therefore accounted for 92% of our totalrevenues. To the extent these and other customers reduce the volumes of naturalgas that they purchase from us and they are not replaced in a timely mannerwith a new customer, our revenues and cash available for distribution coulddecline. However, if we were to lose a customer, we believe we could identify asubstitute purchaser in a timely manner.

 

***Hedging Activities***

 

We enter into hedgingarrangements to reduce the impact of natural gas and oil price volatility onour cash flow from operations. Currently, we use a combination of fixed-priceswaps 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:

 
| ** **          | ** ** | ** **         | ** ** | **Natural Gas**                          | ** **       | **Oil**              | ** ** |
|---------------------|------------|--------------------|------------|-----------------------------------------------|------------------|----------------------|------------|
| ** **          | ** ** | **Production**     | ** ** | **Collars**                                   | ** **       | **Puts**             | ** ** | **Swaps** | ** ** | **Swaps** | ** ** |
| ** **          | ** ** | **Hedged  (Mcfe)** | ** ** | **Floor – Ceiling  ($/MMBtu)** | ** **       | **Floor  ($/MMBtu)** | ** ** | **Price  ($/MMBtu)** | ** ** | **Price  ($/Bbl)** | ** ** |
| Production  Period: |       |               |       |                                          |             |                 |       |   |   |   |   |
| 2008                |       | 6,322,500          |       | $                                             | 7.50 – 9.07 | (1)                  | $          | 7.50 |   | $ | 9.00 |   | $ | 90.30 |   |
| 2009                |       | 5,586,185          |       | $                                             | 7.50 – 9.00 |                 | $          | 7.50 |   | $ | 8.85 |   | $ | 87.23 |   |
| 2010                |       | 4,103,140          |       | $                                             | 8.00 – 9.30 |                 | $          | — |   | $ | 8.76 |   | $ | 85.65 |   |
| 2011                |       | 3,103,512          |       | $                                             | —           |                 | $          | — |   | $ | 7.15 |   | $ | 85.50 |   |
| 2012                |       | 864,000            |       | $                                             | —           |                 | $          | — |   | $ | — |   | $ | 80.00 |   |

 

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

 

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

 

The following summarizesinformation concerning our positions in open interest rate swaps applicable toperiods subsequent to December 31, 2007.

 

| ** **                                      | ** ** | **Principal** | ** ** | **Fixed  Libor** | ** ** |
|-------------------------------------------------|------------|---------------|------------|------------------|------------|
| ** **                                      | ** ** | **Balance**   | ** ** | **Rates**        | ** ** |
| Period:                                         |       |          |       |             |       |
| January 1,  2008 to December 10, 2010 |       | $             | 20,000,000 |             | 3.88       | % |
| January 31,  2008 to January 31, 2011 |       | $             | 30,000,000 |             | 3.00       | % |
| March 31,  2008 to March 31, 2011     |       | $             | 10,000,000 |             | 2.66       | % |

 

***Competition***

 

The natural gas and oilindustry is highly competitive. We encounter strong competition from otherindependent operators and from major oil companies in acquiring properties,leasing acreage, contracting for drilling equipment and securing trainedpersonnel. Many of these competitors have financial and technical resources andstaff substantially larger than ours or a different business model. As aresult, our competitors may be able to pay more for desirable leases, or toevaluate, bid for and purchase a greater number of properties or prospects thanour financial, technical or personnel resources will permit.

 

9

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We are also affected bycompetition for drilling rigs and the availability of related equipment. In thepast, the natural gas and oil industry has experienced shortages of drillingrigs, equipment, pipe and personnel, which has delayed development drilling andother exploitation activities and has caused significant price increases. Weare unable to predict when, or if, such shortages may occur or how they wouldaffect our development and exploitation program. Vinland diversifies suppliersto help manage such shortages.

 

Competition is alsostrong for attractive natural gas producing properties, undeveloped leases anddrilling rights, and we cannot assure unitholders that we will be able tocompete satisfactorily when attempting to make further acquisitions.

 

***Title to Properties***

 

As is customary in thenatural gas and oil industry, we initially conduct only a cursory review of thetitle to our properties on which we do not have proved reserves. Prior to thecommencement of drilling operations on those properties, however, we conduct athorough title examination and perform curative work with respect tosignificant defects. To the extent title opinions or other investigationsreflect title defects on those properties, we are typically responsible forcuring any title defects at our expense. We will not commence drillingoperations on a property until we have cured any material title defects on suchproperty. Prior to completing an acquisition of producing natural gas and oilleases, we perform title reviews on the most significant leases and, dependingon the materiality of properties, we may obtain a title opinion or reviewpreviously obtained title opinions. As a result, we have obtained titleopinions on a significant portion of our natural gas and oil properties andbelieve that we have satisfactory title to our producing properties inaccordance with standards generally accepted in the natural gas and oilindustry. Although title to these properties is subject to encumbrances in somecases, such as customary interests generally retained in connection withacquisition of real property, customary royalty interests, contract terms andrestrictions, liens under operating agreements, liens related to environmentalliabilities associated with historical operations, liens for taxes not yet payableand other burdens, restrictions and minor encumbrances customary in the oil andnatural gas industry, we believe that none of these liens, restrictions,easements, burdens and encumbrances will materially detract from the value ofthese properties or from our interest in these properties, or will materiallyinterfere with our use of these properties in the operation of our business.

 

***Seasonal Nature of Business***

 

Seasonal weatherconditions and lease stipulations can limit our drilling and producing activitiesand other operations in certain areas of the Appalachian region and, as aresult, we generally perform the majority of our drilling during the summermonths. These seasonal anomalies can pose challenges for meeting our welldrilling objectives and increase competition for equipment, supplies andpersonnel during the spring and summer months, which could lead to shortagesand increase costs or delay our operations. Generally, but not always, thedemand for natural gas decreases during the summer months and increases duringthe winter months. Seasonal anomalies such as mild winters or hot summerssometimes lessen this fluctuation. In addition, certain natural gas consumersutilize natural gas storage facilities and purchase some of their anticipated winterrequirements during the summer. This can also lessen seasonal demandfluctuations.

 

***Environmental Matters and Regulation***

 

*General.  *Our business involving the acquisition, development and exploitation of naturalgas and oil properties is subject to extensive and stringent federal, state andlocal laws and regulations governing the discharge of materials into theenvironment or otherwise relating to environmental protection. These operationsare subject to the same environmental laws and regulations as other similarlysituated companies in the natural gas and oil industry. These laws andregulations may:

 
|   | · | require the acquisition  of various permits before drilling commences;                                                                                                    |
|--------|--------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|   |   |                                                                                                                                                                      |
|   | · | require the  installation of expensive pollution control equipment;                                                                                                       |
|   |   |                                                                                                                                                                      |
|   | · | restrict the types,  quantities and concentration of various substances that can be released into  the environment in connection with drilling and production activities; |
|   |   |                                                                                                                                                                      |
|   | · | limit or prohibit  drilling activities on lands lying within wilderness, wetlands and other  protected areas;                                                             |

 

10

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

 

·        imposesubstantial liabilities for pollution resulting from our operations; and

 

·        withrespect to operations affecting federal lands or leases, require preparation ofa Resource Management Plan, an Environmental Assessment, and/or anEnvironmental Impact Statement.

 

These laws, rules andregulations may also restrict the rate of natural gas and oil production belowthe rate that would otherwise be possible. The regulatory burden on the naturalgas and oil industry increases the cost of doing business in the industry andconsequently affects profitability. Additionally, changes in environmental lawsand regulations occur frequently, and any changes that result in more stringentand costly waste handling, disposal and clean-up requirements for the naturalgas and oil industry could have a significant impact on our operating costs. Webelieve that operation of our wells is in substantial compliance with allcurrent applicable environmental laws and regulations and that our continuedcompliance with existing requirements will not have a material adverse impacton our financial condition and results of operations. However, we cannotpredict how future environmental laws and regulations may impact our propertiesor the operations. For the year ended December 31, 2007, we did not incurany material capital expenditures for installation of remediation or pollutioncontrol equipment at any of our facilities. As of the date of this AnnualReport, we are not aware of any environmental issues or claims that willrequire material capital expenditures during 2008 or that will otherwise have amaterial impact on our financial position or results of operations.

 

Environmental laws andregulations that could have a material impact on our operations as well as thenatural gas and oil exploration and production industry in general include thefollowing:

 

*NationalEnvironmental Policy Act.*   Natural gas and oilexploitation and production activities on federal lands are subject to theNational Environmental Policy Act, as amended, or “NEPA”. NEPA requires federalagencies, including the Department of Interior, to evaluate major agencyactions having the potential to significantly impact the environment. In thecourse of such evaluations, an agency will typically prepare an EnvironmentalAssessment to assess the potential direct, indirect and cumulative impacts of aproposed project and, if necessary, will prepare a more detailed EnvironmentalImpact Statement that may be made available for public review and comment. Ourcurrent exploitation and production activities, as well as proposedexploitation and development plans, on federal lands require governmentalpermits or similar authorizations that are subject to the requirements of NEPA.This process has the potential to delay or limit the development of natural gasand oil projects.

 

*WasteHandling.*   The Resource Conservation and RecoveryAct, 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 orall of the provisions of RCRA, sometimes in conjunction with their own, morestringent requirements. While drilling fluids, produced waters, and many otherwastes associated with the exploitation, development, and production of crudeoil, natural gas, or geothermal energy constitute “solid wastes”, which areregulated 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 futureadopt more stringent and costly requirements for the handling of non-hazardouswastes or categorize some non-hazardous wastes as hazardous. We believe that weare in substantial compliance with the requirements of RCRA and related stateand local laws and regulations. Although we do not believe the current costs ofmanaging wastes generated by operation of our wells to be significant, anylegislative or regulatory reclassification of natural gas and oil exploitationand production wastes could increase our costs to manage and dispose of suchwastes.

 

*HazardousSubstance Releases.*   The ComprehensiveEnvironmental Response, Compensation and Liability Act, as amended, also knownas “CERCLA”, or “Superfund,” and analogous state laws, impose joint and severalliability, without regard to fault or legality of conduct, on persons who areconsidered to be responsible for the release of a “hazardous substance” intothe environment. These persons include the owner or operator of the site wherethe release occurred and companies that disposed or arranged for the disposalof the hazardous substance at the site. Under CERCLA, such persons may beliable for the costs of cleaning up the hazardous substances that have beenreleased into the environment, for damages to natural resources and for thecosts of certain health studies. In 

 

11

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addition, it is notuncommon for neighboring landowners and other third parties to file claims forpersonal injury and property damage allegedly caused by the hazardoussubstances released into the environment. While materials are generated in thecourse of operation of our wells that may be regulated as hazardous substances,we have not received any pending notifications that we may be potentiallyresponsible for cleanup costs under CERCLA.

 

We currently own, lease,or have a non-operating interest in numerous properties that have been used fornatural gas and oil exploitation and production for many years. Although webelieve that operating and waste disposal practices have been used that werestandard in the industry at the time, hazardous substances, wastes, orpetroleum hydrocarbons have been released on or under the properties owned orleased by us, or on or under other locations, including off-site locations,where such substances have been taken for disposal. In addition, some of theseproperties have been operated by third parties or by previous owners oroperators whose treatment and disposal of hazardous substances, wastes, orhydrocarbons was not under our control. These properties and the substancesdisposed or released on them may be subject to CERCLA, RCRA and analogous statelaws. Under such laws, we could be required to remove previously disposedsubstances and wastes, remediate contaminated property, or perform remedialplugging or pit closure operations to prevent future contamination.

 

*WaterDischarges.*   The Federal Water Pollution ControlAct, as amended, or “Clean Water Act”, and analogous state laws imposerestrictions and strict controls on the discharge of pollutants, includingproduced waters and other natural gas and oil wastes, into state waters as wellas waters of the United States. The discharge of pollutants into regulatedwaters is prohibited, except in accordance with the terms of a permit issued byEPA or the relevant state. The Clean Water Act also prohibits the discharge ofdredge and fill material in regulated waters, including wetlands, unlessauthorized by a permit issued by the U.S. Army Corps of Engineers. Federal andstate regulatory agencies can impose administrative, civil and criminalpenalties for non-compliance with discharge permits or other requirements ofthe Clean Water Act and analogous state laws and regulations. We believe we arein substantial compliance with the requirements of the Clean Water Act.

 

*AirEmissions.*   The Clean Air Act, as amended, andassociated state laws and regulations, regulate emissions of various airpollutants through the issuance of permits and the imposition of otherrequirements. In addition, EPA has developed, and continues to develop,stringent regulations governing emissions of toxic air pollutants at specifiedsources. Some of our new facilities may be required to obtain permits beforework can begin, and existing facilities may be required to incur capital costsin order to comply with new emission limitations. These regulations mayincrease the costs of compliance for some facilities, and federal and stateregulatory agencies can impose administrative, civil and criminal penalties fornon-compliance. We believe that we are in substantial compliance with therequirements of the Clean Air Act.

 

*OSHA.*  We are subject to the requirements of the federal Occupational Safety andHealth Act, as amended, or “OSHA”, and comparable state statutes. The OSHAhazard communication standard, EPA community right-to-know regulations underthe Title III of CERCLA and similar state statutes require that we organizeand/or disclose information about hazardous materials used or produced in ouroperations. We believe that we are in substantial compliance with theapplicable requirements of OSHA.

 

*GlobalWarming and Climate Control*.  In response to recent studiessuggesting that emissions of certain gases, referred to as “greenhouse gases”and including carbon dioxide and methane, may be contributing to warming of theEarth’s atmosphere, the current session of the U.S. Congress is consideringclimate change-related legislation to restrict greenhouse gas emissions.  One bill recently approved by the U.S. SenateEnvironment and Public Works Committee, known as the Lieberman-Warner ClimateSecurity Act or S.2191, would require a 70% reduction in emissions ofgreenhouse gases from sources within the United States between 2012 and 2050.The Lieberman-Warner bill proposes a “cap and trade” scheme of regulation ofgreenhouse gas emissions — a ban on emissions above a defined reducing annualcap. Covered parties will be authorized to emit greenhouse emissions throughthe acquisition and subsequent surrender of emission allowances that may betraded or acquired on the open market. Debate and a possible vote on this bill by the full Senate areanticipated to occur before mid-year 2008. In addition, at least one-third ofthe states have already taken legal measures to reduce emissions of greenhousegases, primarily through the planned development of greenhouse gas emissioninventories and/or regional greenhouse gas cap and trade programs. Depending onthe particular program, we could be required to purchase and surrenderallowances, either for greenhouse gas emissions resulting from our operationsor 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 certainprovisions of the Clean Air Act, the EPA may regulate carbon dioxide and othergreenhouse gas emissions from mobile sources such as cars and trucks, even ifCongress does not adopt new legislation specifically addressing emissions ofgreenhouse gases. The EPA has publicly stated its goal of issuing a proposed rule toaddress carbon dioxide and other greenhouse gas emissions from vehicles andautomobile fuels but the timing for issuance of this proposed rule isunsettled as the agency reviews its mandates under the Energy Independence andSecurity Act of 2007, which includes expanding the use of renewable fuels andraising the corporate average fuel economy standards. The Court’s holding inthe *Massachusetts* decision thatgreenhouse gases including carbon dioxide fall under the federal Clean Air Act’sdefinition of “air pollutant” may also result in future regulation of carbondioxide and other greenhouse gas emissions from stationary sources undercertain CAA programs. New federal or state laws requiring adoption of astringent greenhouse gas control program or imposing restrictions on emissionsof carbon dioxide in areas of the United States in which we conduct businesscould adversely affect our cost of doing business and demand for our naturalgas and oil.

 

***Other Regulation of the Natural Gas and OilIndustry***

 

The natural gas and oil industryis extensively regulated by numerous federal, state and local authorities.Legislation affecting the natural gas and oil industry is under constant reviewfor amendment or expansion, frequently increasing the regulatory burden. Also,numerous departments and agencies, both federal and state, are authorized bystatute to issue rules and regulations binding on the natural gas and oilindustry and its individual members, some of which carry substantial penaltiesfor failure to comply. Although the regulatory burden on the natural gas andoil industry increases our cost of doing business and, consequently, affectsour profitability, these burdens generally do not affect us any differently orto any greater or lesser extent than they affect other companies in theindustry with similar types, quantities and locations of production.

 

Legislation continues tobe introduced in Congress and development of regulations continues in theDepartment of Homeland Security and other agencies concerning the security of industrialfacilities, including natural gas and oil facilities. Our operations may besubject to such laws and regulations. If in the future one or more of ourfacilities becomes subject to such legislation, then the cost to comply withsuch law could be substantial.

 

*Drillingand Production.*   Our operations are subject tovarious types of regulation at the federal, state and local levels. These typesof regulation include requiring permits for the drilling of wells, drillingbonds and reports concerning operations. Most states, and some counties andmunicipalities, in which we operate also regulate one or more of the following:

 
|   | · | the location of wells;                                                       |
|--------|--------|------------------------------------------------------------------------------|
|   |   |                                                                         |
|   | · | the method of drilling  and casing wells;                                    |
|   |   |                                                                         |
|   | · | the surface use and  restoration of properties upon which wells are drilled; |
|   |   |                                                                         |
|   | · | the plugging and  abandoning of wells; and                                   |
|   |   |                                                                         |
|   | · | notice to surface  owners and other third parties.                           |

 

State laws regulate thesize and shape of drilling and spacing units or proration units governing thepooling of natural gas and oil properties. Some states allow forced pooling orintegration of tracts to facilitate exploitation while other states rely onvoluntary pooling of lands and leases. In some instances, forced pooling orunitization may be implemented by third parties and may reduce our interest inthe unitized properties. In addition, state conservation laws establish maximumrates of production from natural gas and oil wells, generally prohibit theventing or flaring of natural gas and impose requirements regarding theratability of production. These laws and regulations may limit the amount ofnatural gas and oil we can produce from our wells or limit the number of wellsor the locations at which we can drill. Moreover, each state generally imposesa production or severance tax with respect to the production and sale of oil,natural gas and natural gas liquids within its jurisdiction.

 

*NaturalGas Regulation.*   The availability, terms and costof transportation significantly affect sales of natural gas. The interstatetransportation and sale for resale of natural gas is subject to federalregulation, including regulation of the terms, conditions and rates forinterstate transportation, storage and various other matters, primarily by theFederal Energy Regulatory Commission, or “FERC”.

 

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Federal and stateregulations govern the price and terms for access to natural gas pipelinetransportation. The FERC’s regulations for interstate natural gas transmissionin some circumstances may also affect the intrastate transportation of naturalgas.

 

In August 2005,Congress enacted the Energy Policy Act of 2005, or “EP Act 2005”. Among othermatters, EP Act 2005 amends the Natural Gas Act, or “NGA”, to make it unlawfulfor any entity, as defined in the EP Act 2005, including otherwisenon-jurisdictional producers such as us, to use any deceptive or manipulativedevice or contrivance in connection with the purchase or sale of natural gas orthe purchase or sale of transportation services regulated by the FERC thatviolates the FERC’s rules. On January 19, 2006, the FERC issued rules implementingthe provision of the EP Act of 2005. The rules make it unlawful for anyentity, directly or indirectly, to use or employ any device, scheme, orartifice to defraud; to make any untrue statement of material fact or omit tomake 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 anyperson in connection with the purchase or sale of natural gas subject to thejurisdiction of the FERC, or the purchase or sale of transportation servicessubject to the jurisdiction of the FERC. The EP Act 2005 also gives the FERCauthority to impose civil penalties for violations of the NGA up to $1,000,000per day per violation. While the EP Act 2005 reflects a significant expansionof the FERC’s enforcement authority, we do not anticipate that we will beaffected by the EP Act 2005 any differently than other producers of naturalgas.

 

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

 

*StateRegulation.*   The various states regulate thedrilling for, and the production, gathering and sale of, natural gas and oil,including imposing severance taxes and requirements for obtaining drillingpermits. For example, currently, a severance tax on natural gas and oilproduction is imposed at a rate of 4.5%, 3.0% and 3.75% in Kentucky, Tennesseeand New Mexico, respectively. Texas currently imposes a 7.5% severance tax ongas production and 4.6% severance tax on oil production. States also regulatethe method of developing new fields, the spacing and operation of wells and theprevention of waste of natural gas resources. States may regulate rates ofproduction and may establish maximum daily production allowables from naturalgas wells based on market demand or resource conservation, or both. States donot regulate wellhead prices or engage in other similar direct economicregulation, but there can be no assurance that they will not do so in thefuture. The effect of these regulations may be to limit the amounts of naturalgas that may be produced from our wells, and to limit the number of wells or locationswe can drill.

 

The petroleum industry isalso subject to compliance with various other federal, state and localregulations and laws. Some of those laws relate to occupational safety,resource conservation and equal employment opportunity. We do not believe thatcompliance with these laws will have a material adverse effect upon theunitholders.

 

***Employees***

 

As of December 31,2007, we had four full time employees. All of our employees work in our Houstonoffice. Under the management services agreement with Vinland, we will rely onVinland’s employees to operate our existing producing wells in Appalachia andcoordinate our development drilling program in Appalachia. We also contract forthe services of independent consultants involved in land, regulatory,accounting, financial and other disciplines as needed. None of our employeesare represented by labor unions or covered by any collective bargainingagreement. We believe that our relations with our employees are satisfactory.

 

***Offices***

 

We entered into a leaseagreement in January 2007 for approximately 2,320 square feet of officespace 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 thequarterly distribution on our common units.***

 

We may not havesufficient cash flow from operations each quarter to pay the quarterly distribution.Under the terms of our limited liability company agreement, the amount of cashotherwise available for distribution will be reduced by our operating expensesand the amount of any cash reserve amounts that our board of directorsestablishes to provide for future operations, future capital expenditures andfuture debt service requirements. The amount of cash we can distribute on ourcommon units principally depends upon the amount of cash we generate from ouroperations, which will fluctuate from quarter to quarter based on, among otherthings:

 
|   | · | the amount of natural  gas and oil we produce;                                                                            |
|--------|--------|---------------------------------------------------------------------------------------------------------------------------|
|   |   |                                                                                                                      |
|   | · | the demand of our  natural gas and oil production;                                                                        |
|   |   |                                                                                                                      |
|   | · | the price at which we  are able to sell our natural gas and oil production;                                               |
|   |   |                                                                                                                      |
|   | · | the level of our  operating costs;                                                                                        |
|   |   |                                                                                                                      |
|   | · | our ability to continue  our development activities at economically attractive costs;                                     |
|   |   |                                                                                                                      |
|   | · | the results of our  hedging activities;                                                                                   |
|   |   |                                                                                                                      |
|   | · | the level of our  interest expense which depends on the amount of our indebtedness and the  interest payable thereon; and |
|   |   |                                                                                                                      |
|   | · | the level of our  capital expenditures.                                                                                   |

 

In addition, the actualamount of cash we will have available for distribution will depend on otherfactors, some of which are beyond our control, including:

 
|   | · | the level of our  capital expenditures;                                                                        |
|--------|--------|----------------------------------------------------------------------------------------------------------------|
|   |   |                                                                                                           |
|   | · | our ability to make  working capital borrowings under our reserve-based credit facility to pay  distributions; |
|   |   |                                                                                                           |
|   | · | the cost of  acquisitions, if any;                                                                             |
|   |   |                                                                                                           |
|   | · | our debt service  requirements;                                                                                |
|   |   |                                                                                                           |
|   | · | fluctuations in our  working capital needs;                                                                    |
|   |   |                                                                                                           |
|   | · | timing and collectibility  of receivables;                                                                     |
|   |   |                                                                                                           |
|   | · | restrictions on  distributions contained in our reserve-based credit facility;                                 |
|   |   |                                                                                                           |
|   | · | prevailing economic  conditions; and                                                                           |
|   |   |                                                                                                           |
|   | · | the amount of cash  reserves established by our board of directors for the proper conduct of our  business.    |

 

As a result of thesefactors, the amount of cash we distribute in any quarter to our unitholders mayfluctuate significantly from quarter to quarter. If we do not achieve ourexpected operational results or cannot borrow the amounts needed, we may not beable to pay the full, or any, amount of the quarterly distribution, in whichevent 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 orinadequately performs, our operations will be disrupted and our costs couldincrease or our reserves may not be developed, reducing our future levels ofproduction and our cash from operations, which could affect our ability to makecash distributions to our unitholders.***

 

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Effective as of January 5,2007, we entered into various agreements with Vinland, an affiliate of ourlargest unitholder, under which we rely on Vinland to operate all of ourexisting producing wells and coordinate our development drilling program inAppalachia. For example, pursuant to a participation agreement that we haveentered into with Vinland, Vinland generally has control over our drilling programin Appalachia and has the sole right to determine which wells are drilled untilJanuary 1, 2011. Under the agreements, Vinland will also advise andconsult with us regarding all aspects of our production and developmentoperations in Appalachia and provide us with administrative support services asnecessary or useful for the operation of our business. If Vinland fails to orinadequately performs these functions, our operations in Appalachia will bedisrupted and our costs could increase or our reserves may not be developed orproperly developed, reducing our future levels of production and our cash fromoperations, which could affect our ability to make cash distributions to ourunitholders.

 

***Natural gas and oil prices are volatile. If commodity pricesdecline significantly for a temporary or prolonged period, our cash flow fromoperations may decline and we may have to lower our distributions or may not beable to pay distributions at all.***

 

Our revenue,profitability and cash flow depend upon the prices and demand for natural gasand oil. The natural gas and oil markets are very volatile and a drop in pricescan significantly affect our financial results and impede our growth. Changesin natural gas and oil prices have a significant impact on the value of ourreserves and on our cash flow. Prices for natural gas and oil may fluctuatewidely in response to relatively minor changes in the supply of and demand fornatural gas and oil, market uncertainty and a variety of additional factorsthat are beyond our control, such as:

 
|   | · | the domestic and  foreign supply of and demand for natural gas and oil;                                                                       |
|--------|--------|-----------------------------------------------------------------------------------------------------------------------------------------------|
|   |   |                                                                                                                                          |
|   | · | the price and level of  foreign imports;                                                                                                      |
|   |   |                                                                                                                                          |
|   | · | the level of consumer  product demand;                                                                                                        |
|   |   |                                                                                                                                          |
|   | · | weather conditions;                                                                                                                           |
|   |   |                                                                                                                                          |
|   | · | overall domestic and  global economic conditions;                                                                                             |
|   |   |                                                                                                                                          |
|   | · | political and economic  conditions in natural gas and oil producing countries, including those in the  Middle East, Africa and South America; |
|   |   |                                                                                                                                          |
|   | · | the ability of members  of the Organization of Petroleum Exporting Countries to agree to and maintain  oil price and production controls;     |
|   |   |                                                                                                                                          |
|   | · | the impact of the U.S.  dollar exchange rates on natural gas and oil prices;                                                                  |
|   |   |                                                                                                                                          |
|   | · | technological advances  affecting energy consumption;                                                                                         |
|   |   |                                                                                                                                          |
|   | · | domestic and foreign  governmental regulations and taxation;                                                                                  |
|   |   |                                                                                                                                          |
|   | · | the impact of energy  conservation efforts;                                                                                                   |
|   |   |                                                                                                                                          |
|   | · | the proximity and  capacity of natural gas and oil pipelines and other transportation  facilities; and                                        |
|   |   |                                                                                                                                          |
|   | · | the price and  availability of alternative fuels.                                                                                             |

 

Although we intend tohave an ongoing natural gas price hedging strategy, there is no assurance thatit will effectively negate the impact of price fluctuations on all of ourproduction. 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 froma high of $7.59 per MMBtu to a low of $5.84 per MMBtu. If we raise our cashdistribution level in response to increased cash flow during periods ofrelatively high commodity prices, we may not be able to sustain thosedistribution levels during periods of sustained lower commodity prices.

 

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***Unless we replace our reserves, our existing reserves andproduction will decline, which would adversely affect our cash flow fromoperations and our ability to make distributions to our unitholders.***

 

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

 

***Ouracquisition activities will subject us to certain risks.***

 

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

 

Ourdecision to acquire a property will depend in part on the evaluation of dataobtained from production reports and engineering studies, geophysical andgeological analyses and seismic and other information, the results of which areoften inconclusive and subject to various interpretations. Also, our reviews ofacquired properties are inherently incomplete because it generally is notfeasible to perform an in-depth review of the individual properties involved ineach acquisition. Even a detailed review of records and properties may notnecessarily reveal existing or potential problems, nor will it permit us tobecome sufficiently familiar with the properties to assess fully theirdeficiencies and potential. Inspections may not always be performed on every well,and environmental problems, such as ground water contamination, are notnecessarily observable even when an inspection is undertaken.

 

If our Permian Basinacquisition or other potential acquisitions do not generate increases inavailable cash per unit, our ability to make cash distributions to ourunitholders could materially decrease.

 

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

 

Pursuant to aparticipation agreement that we have entered into with Vinland, Vinlandgenerally has control over our drilling program in Appalachia and has the soleright to determine which wells are drilled until January 1, 2011. Duringthis period, we will meet with Vinland on a quarterly basis to review Vinland’sproposal to drill not less than 25 nor more than 40 gross wells, in which wewill own a 40% working interest, in any quarter. Up to 20% of the proposedwells may be carried over and added to the wells to be drilled in thesubsequent quarter, provided that Vinland is required to drill at least 100gross wells per calendar year. If Vinland proposes the drilling of less than 25gross wells in any quarter, we have the right to propose the drilling of up toa total of 14 net wells, in which we will own a 100% working interest, in agiven quarterly period. If Vinland drills its minimum commitment, we do nothave the ability to drill our own additional wells in the AMI. If either partyelects not to participate in the drilling of the proposed wells or futureoperations with respect to drilled wells, such party forfeits all right, titleand interest in the natural gas and oil production that may be produced fromsuch wells. 

 

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The participationagreement will remain in place for four years and shall continue thereafter ona year to year basis until such time as either party elects to terminate theagreement. The obligations of the parties with respect to the drilling programdescribed above will expire in three years.

 

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

 

We currentlyonly operate 49 of our 390 gross wells in the Permian Basin.  In addition, we expect that a substantialmajority of future wells on our existing Permian Basin properties will beoperated by third parties.  As a result,the success and timing of our drilling and development activities on suchnonoperated properties depend upon a number of factors, including:  

 

·   the nature and timing of drilling and operationalactivities; 

 

·   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 arenot conducted on these properties or are not conducted on a timely basis, wemay 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 toparticipate under our participation and operating agreements with Vinland inthe drilling of these wells.***

 

Under the terms of ourparticipation and operating agreements with Vinland, we may elect to foregoparticipation in the future drilling of wells. Should we do so, we will becomeobligated to transfer without compensation all of our right, title and interestin those wells.

 

***We are exposed to the credit risk of Vinland and anymaterial nonperformance by Vinland could reduce our ability to makedistributions to our unitholders.***

 

Effective January 5,2007, we entered into several agreements with Vinland pursuant to which Vinlandoperates all of our existing producing wells in Appalachia and coordinates ourdevelopment drilling program in Appalachia. In addition, Vinland generally hascontrol over our drilling program in Appalachia and has the sole right todetermine which wells are drilled until January 1, 2011. In the eventVinland becomes insolvent or is declared bankrupt, we would have to become theoperator of our wells in Appalachia and pursue our own drilling program, whichwould require additional employees and increased expenses. In addition, thereare no restrictions on Nami from selling his ownership in Vinland to a thirdparty that should, but may not perform under our agreements with Vinland. Anymaterial nonperformance under our agreements with Vinland could materially andadversely impact our ability to operate and make distributions to ourunitholders.

 

***The amount of cash that we have available for distributionto our unitholders depends primarily upon our cash flow and not ourprofitability.***

 

The amount of cash thatwe have available for distribution depends primarily on our cash flow,including cash from reserves and working capital or other borrowings, and notsolely 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 wemay pay distributions during periods when we incur net losses.

 

***Our estimated reserves are based on many assumptions thatmay prove to be inaccurate. Any material inaccuracies in these reserveestimates or underlying assumptions will materially affect the quantities andpresent value of our reserves.***

 

No one can measureunderground accumulations of natural gas in an exact way. Natural gas reserveengineering requires subjective estimates of underground accumulations ofnatural gas and assumptions concerning future natural gas prices, productionlevels, and operating and development costs. As a result, estimated quantitiesof proved reserves and projections of future production rates and the timing ofdevelopment expenditures may prove to be inaccurate. Independent petroleumengineers prepare estimates of our proved reserves. Some of our reserveestimates are made without the benefit of a lengthy production history, whichare less reliable than estimates based on a lengthy production history. Also,we make certain assumptions regarding future natural gas prices, productionlevels, and operating and development costs that may prove incorrect. Anysignificant variance from these assumptions by actual figures could greatlyaffect our estimates of reserves, the economically recoverable quantities ofnatural gas attributable to any particular group of properties, theclassifications of reserves based on risk of recovery, and estimates of thefuture net cash flows. For example, if natural gas prices decline by $1.00 perMMBtu, the standardized measure of our proved reserves as of December 31,2007 would decrease from $151.0 million to $120.0 million, based on pricesensitivity generated from an internal evaluation. Our standardized measure iscalculated using unhedged natural gas prices and is determined in accordancewith the rules and regulations of the SEC. Numerous changes over time tothe assumptions on which our reserve estimates are based, as described above,often result in the actual quantities of natural gas we ultimately recoverbeing different from our reserve estimates.

 

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

 

 

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***The present value of future net cash flows from our provedreserves is not necessarily the same as the current market value of ourestimated natural gas reserves.***

 

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

 

·        supplyof and demand for natural gas;

 

·        actualprices we receive for natural gas;

 

·        ouractual operating costs in providing natural gas;

 

·        theamount and timing of our capital expenditures;

 

·        theamount and timing of actual production; and

 

·        changesin governmental regulations or taxation.

 

The timing of both ourproduction and our incurrence of expenses in connection with the developmentand production of natural gas properties will affect the timing of actualfuture net cash flows from proved reserves, and thus their actual presentvalue. In addition, the 10% discount factor we use when calculating discountedfuture net cash flows may not be the most appropriate discount factor based oninterest rates in effect from time to time and risks associated with us or thenatural gas industry in general. Any material inaccuracies in these reserveestimates or underlying assumptions will materially affect the quantities andpresent value of our reserves, which could adversely affect our business,results of operations, financial condition and our ability to make cashdistributions to unitholders.

 

***Our operations require substantial capital expenditures,which will reduce our cash available for distribution. We may be unable toobtain needed capital or financing on satisfactory terms, which could lead to adecline in our reserves and adversely affect our ability to make distributionsto our unitholders.***

 

The natural gas and oilindustry is capital intensive. We make and expect to continue to makesubstantial capital expenditures in our business for the development,production and acquisition of natural gas reserves. These expenditures willreduce our cash available for distribution. We intend to finance our futurecapital expenditures with cash flow from operations and our financingarrangements. Our cash flow from operations and access to capital are subjectto a number of variables, including:

 

·        ourproved reserves;

 

·        thelevel of natural gas and oil we are able to produce from existing wells;

 

·        theprices at which our natural gas and oil is sold; and

 

·        ourability to acquire, locate and produce new reserves.

 

If our revenues or theborrowing base under our reserve-based credit facility decrease as a result oflower natural gas and oil prices, operating difficulties, declines in reservesor for any other reason, we may have limited ability to obtain the capitalnecessary to sustain our operations at current levels or to replace or add toour reserves. Our reserve-based credit facility restricts our ability to obtainnew debt financing. If additional capital is needed, we may not be able toobtain debt or equity financing on terms favorable to us, or at all. If cashgenerated by operations or available under our reserve-based credit facility isnot sufficient to meet our capital requirements, the failure to obtainadditional financing could result in a curtailment of our operations relatingto development of our prospects, which in turn could lead to a possible declinein our reserves and production and a reduction in our cash available fordistribution.

 

***Our business depends on gathering and compression facilitiesowned by Vinland and transportation facilities owned by Delta Natural Gas,Columbia Gas Transmission and other third-party transporters and we rely on Vinlandto gather and deliver our natural gas to certain designated interconnects withthird-party transporters.***

 

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***Any limitation in the availability of those facilities ordelay in providing interconnections to newly drilled wells would interfere withour ability to market the natural gas we produce and could reduce our revenuesand 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 providesthe services necessary for us to market our natural gas production in the areaof mutual interest. Vinland delivers our natural gas production to certaindesignated interconnects with third-party transporters including Delta NaturalGas and Columbia Gas Transmission. As a result, the marketability of ournatural gas production depends in part on the availability, proximity andcapacity of Vinland’s, Delta’s, and Columbia’s pipeline systems. The amount ofnatural gas that can be produced and sold is subject to curtailment in certaincircumstances, such as pipeline interruptions due to scheduled and unscheduledmaintenance, excessive pressure, physical damage to the gathering, compressionor transportation system, or lack of contracted capacity on such systems. Thecurtailments arising from these and similar circumstances may last from a fewdays to several months. In many cases, we are provided only with limited, ifany, notice as to when these circumstances will arise and their duration. Inaddition, some of our wells are drilled in locations that are not serviced bygathering and transportation pipelines, or the gathering and transportationpipelines in the area may not have sufficient capacity to transport theadditional production. As a result, we may not be able to sell the natural gasproduction from these wells until the necessary gathering and transportationsystems are constructed. Any significant curtailment in gathering system orpipeline capacity, or significant delay in the construction of necessarygathering, compression and transportation facilities, could reduce our revenuesand cash available for distribution. Finally, if we drill wells in locationsthat are not serviced by Vinland’s gathering pipelines, we may need to contractwith a third-party to deliver our production which may not be as favorable tous as our agreement with Vinland.

 

***Future price declines may result in a write-down of ourasset carrying values.***

 

Lower natural gas and oilprices may not only decrease our revenues, but also reduce the amount ofnatural gas and oil that we can produce economically. This may result in ourhaving to make substantial downward adjustments to our estimated provedreserves. If this occurs, or if our estimates of development costs increase,production data factors change or drilling results deteriorate, accounting rules mayrequire us to write down, as a non-cash charge to earnings, the carrying valueof our natural gas properties for impairments. We are required to performimpairment tests on our assets whenever events or changes in circumstances leadto a reduction of the estimated useful life or estimated future cash flows thatwould indicate that the carry amount may not be recoverable or whenevermanagement’s plans change with respect to those assets. We may incur impairmentcharges in the future, which could have a material adverse effect on ourresults of operations in the period taken and our ability to borrow funds underour reserve-based credit facility, which may affect our ability to fund ouroperations and acquire additional reserves, which may adversely affect ourability to make cash distributions to our unitholders.

 

***We depend on certain key customers for sales of our naturalgas. To the extent these and other customers reduce the volumes of natural gasthey purchase from us, our revenues and cash available for distribution coulddecline.***

 

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 EnergyPartners, LLC accounted for approximately 41%, 16%, 13%, 11% and 11%,respectively, of our total revenues. Our top five purchasers during the yearended December 31, 2007, therefore accounted for 92% of our totalrevenues. To the extent these and other customers reduce the volumes of naturalgas that they purchase from us and they are not replaced in a timely mannerwith a new customer, our revenues and cash available for distribution coulddecline.

 

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

 

The operations of ourwells are subject to stringent and complex federal, state and localenvironmental laws and regulations. These include, for example:

 

·        the federal Clean Air Actand comparable state laws and regulations that impose obligations related toair emissions;

 

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·        the federal Clean WaterAct and comparable state laws and regulations that impose obligations relatedto discharges of pollutants into regulated bodies of water;

 

·        RCRA and comparable statelaws that impose requirements for the handling and disposal of waste from ourfacilities; and

 

·        CERCLA and comparablestate laws that regulate the cleanup of hazardous substances that may have beenreleased at properties currently or previously owned or operated by us or atlocations to which we have sent hazardous substances for disposal.

 

Failure to comply withthese laws and regulations may trigger a variety of administrative, civil andcriminal enforcement measures, including the assessment of monetary penalties,the imposition of remedial requirements, and the issuance of orders enjoiningfuture operations. Certain environmental statutes, including the RCRA, CERCLA,the federal Oil Pollution Act and analogous state laws and implementingregulations, impose strict, joint and several liability for costs required toclean up and restore sites where hazardous substances or wastes have beendisposed of or otherwise released. Moreover, it is not uncommon for neighboringlandowners and other third parties to file claims for personal injury andproperty or natural resource damage allegedly caused by the release ofhazardous substances or other waste products into the environment.

 

We may incur significantenvironmental costs and liabilities due to the nature of our business and thehazardous substances and wastes associated with operation of the wells. Forexample, an accidental release of petroleum hydrocarbons from one of our wellscould subject us to substantial liabilities arising from environmental cleanupand restoration costs, claims made by neighboring landowners and other thirdparties for personal injury, property and natural resource damage, and fines orpenalties for related violations of environmental laws or regulations.Moreover, the possibility exists that stricter laws, regulations or enforcementpolicies could significantly increase our compliance costs and the cost of anyremediation that may become necessary. We may not be able to recover some orany of these costs from insurance. Please read “Item1—Business—Operations—Environmental Matters and Regulation.”

 

***Our future distributions and proved reserves will bedependent upon the success of our efforts to prudently acquire, manage anddevelop natural gas and oil properties that conform to the acquisition profiledescribed in this Annual Report.***

 

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

 

Suitable acquisitioncandidates may not be available on terms and conditions that we findacceptable, and acquisitions pose substantial risks to our businesses,financial conditions and results of operations. Even if future acquisitions arecompleted, 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 acquiredproperties may not produce revenues, reserves, earnings or cash flow atanticipated levels;

 

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

 

·        we may be unable tointegrate acquired properties successfully and may not realize anticipatedeconomic, operational and other benefits in a timely manner, which could resultin substantial costs and delays or other operational, technical or financialproblems;

 

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

 

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·        we may incur additionaldebt related to future acquisitions.

 

***Substantial acquisitions or other transactions could requiresignificant external capital and could change our risk and property profile.***

 

A principal component ofour business strategy is to grow our asset base and production through theacquisition of natural gas and oil properties characterized by long-lived,stable production. The character of the newly acquired properties may besubstantially different in operating or geological characteristics orgeographic location than our existing properties. The changes in thecharacteristics and risk profiles of such new properties will in turn affectour risk profile, which may negatively affect our ability to issue equity ordebt securities in order to fund future acquisitions and may inhibit ourability to renegotiate our existing credit facilities on favorable terms.

 

***Locations that we decide to drill may notyield natural gas in commercially viable quantities.***

 

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

 

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

 

Many of our leases are inareas that have already been partially depleted or drained by earlier offsetdrilling. This may inhibit our ability to find economically recoverablequantities of natural gas in these areas.

 

***Our identified drilling location inventories are scheduledout over several years, making them susceptible to uncertainties that couldmaterially alter the occurrence or timing of their drilling, resulting intemporarily lower cash from operations, which may impact our ability to paydistributions.***

 

Our management hasspecifically identified and scheduled drilling locations as an estimation ofour future multi-year drilling activities on our existing acreage. As of December 31,2007, we had identified 326 proved undeveloped drilling locations and over 217additional drilling locations in Appalachia. These identified drillinglocations represent a significant part of our strategy. Our ability to drilland develop these locations depends on a number of factors, including the availabilityof capital, seasonal conditions, regulatory approvals, natural gas prices,drilling and operating costs and drilling results. In addition, NSAI has notassigned any proved reserves to the over 217 unproved drilling locations wehave identified and scheduled for drilling and therefore there may existgreater uncertainty with respect to the success of drilling wells at thesedrilling locations. Our final determination on whether to drill any of thesedrilling locations will be dependent upon the factors described above as wellas, to some degree, the results of our drilling activities with respect to ourproved drilling locations. Because of these uncertainties, we do not know ifthe numerous drilling locations we have identified will be drilled within ourexpected timeframe or will ever be drilled or if we will be able to producenatural gas from these or any other potential drilling locations. As such, ouractual drilling activities may materially differ from those presentlyidentified, which could adversely affect our business.

 

***Drilling for and producing natural gas are high riskactivities with many uncertainties that could adversely affect our financialcondition or results of operations and, as a result, our ability to paydistributions to our unitholders.***

 

Our drilling activitiesare subject to many risks, including the risk that we will not discovercommercially productive reservoirs. Drilling for natural gas can beuneconomical, not only from dry holes, but also from productive wells that donot produce sufficient revenues to be commercially viable. In addition, ourdrilling and producing operations may be curtailed, delayed or canceled as aresult of other factors, including:

 
|   | · | the high cost,  shortages or delivery delays of equipment and services; |
|--------|--------|-------------------------------------------------------------------------|
|   |   |                                                                    |
|   | · | unexpected operational  events;                                         |
|   |   |                                                                    |
|   | · | adverse weather  conditions;                                            |

 

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|   | · | facility or equipment  malfunctions;                                |
|--------|--------|---------------------------------------------------------------------|
|   |   |                                                                |
|   | · | title problems;                                                     |
|   |   |                                                                |
|   | · | pipeline ruptures or  spills;                                       |
|   |   |                                                                |
|   | · | compliance with environmental  and other governmental requirements; |
|   |   |                                                                |
|   | · | unusual or unexpected  geological formations;                       |
|   |   |                                                                |
|   | · | loss of drilling fluid  circulation;                                |
|   |   |                                                                |
|   | · | formations with  abnormal pressures;                                |
|   |   |                                                                |
|   | · | fires;                                                              |
|   |   |                                                                |
|   | · | blowouts, craterings  and explosions;                               |
|   |   |                                                                |
|   | · | uncontrollable flows of  natural gas or well fluids; and            |
|   |   |                                                                |
|   | · | pipeline capacity  curtailments.                                    |

 

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

 

We ordinarily maintaininsurance 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 costof available insurance is excessive relative to the perceived risks presented.Losses could therefore occur for uninsurable or uninsured risks or in amountsin excess of existing insurance coverage. The occurrence of an event that isnot fully covered by insurance could have a material adverse impact on ourbusiness activities, financial condition and results of operations.

 

***We may incur substantial additional debt in the future toenable us to pursue our business plan and to pay distributions to ourunitholders.***

 

Our business requires asignificant amount of capital expenditures to maintain and grow productionlevels. Commodity prices have historically been volatile, and we cannot predictthe prices we will be able to realize for our production in the future. As aresult, we may borrow significant amounts under our reserve-based creditfacility in the future to enable us to pay quarterly distributions. Significantdeclines in our production or significant declines in realized natural gasprices for prolonged periods and resulting decreases in our borrowing base mayforce us to reduce or suspend distributions to our unitholders.

 

When we borrow to paydistributions, we are distributing more cash than we are generating from ouroperations on a current basis. This means that we are using a portion of ourborrowing capacity under our reserve-based credit facility to pay distributionsrather than to maintain or expand our operations. If we use borrowings underour reserve-based credit facility to pay distributions for an extended periodof time rather than toward funding capital expenditures and other mattersrelating to our operations, we may be unable to support or grow our business.Such a curtailment of our business activities, combined with our payment ofprincipal and interest on our future indebtedness to pay these distributions,will reduce our cash available for distribution on our common units. If weborrow to pay distributions during periods of low commodity prices andcommodity prices remain low, we may have to reduce or suspend our distributionin order to avoid excessive leverage and debt covenant violations.

 

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

 

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We are prohibited fromborrowing under our reserve-based credit facility to pay distributions tounitholders if the amount of borrowings outstanding under our reserve-basedcredit facility reaches or exceeds 90% of the borrowing base. Our borrowingbase is the amount of money available for borrowing, as determinedsemi-annually by our lenders in their sole discretion. The lenders willredetermine the borrowing base based on an engineering report with respect toour natural gas reserves, which will take into account the prevailing naturalgas prices at such time. We anticipate that if, at the time of anydistribution, our borrowings equal or exceed 90% of the then-specifiedborrowing base, our ability to pay distributions to our unitholders in any suchquarter will be solely dependent on our ability to generate sufficient cashfrom our operations.

 

The lenders canunilaterally adjust the borrowing base and the borrowings permitted to beoutstanding under our reserve-based credit facility. Any increase in theborrowing base requires the consent of all the lenders. Outstanding borrowingsin excess of the borrowing base must be repaid immediately, or we must pledgeother natural gas and oil properties as additional collateral. We do notcurrently have any substantial unpledged properties, and we may not have thefinancial resources in the future to make any mandatory principal prepaymentsrequired under our reserve-based credit facility.

 

***Seasonal weather conditions and lease stipulations adverselyaffect our ability to conduct drilling activities in some of the areas where weoperate.***

 

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

 

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

 

One of our growthstrategies is to capitalize on opportunistic acquisitions of natural gas andoil reserves. However, our reviews of acquired properties are inherentlyincomplete because it generally is not feasible to review in depth everyindividual property involved in each acquisition. Even a detailed review ofrecords and properties may not necessarily reveal existing or potentialproblems, nor will it permit a buyer to become sufficiently familiar with theproperties to assess fully their deficiencies and potential. Inspections maynot always be performed on every well, and environmental problems, such asground water contamination, are not necessarily observable even when aninspection is undertaken.

 

***Our hedging activities could result in financial losses orcould reduce our income, which may adversely affect our ability to paydistributions to our unitholders.***

 

We enter into hedgingarrangements to reduce the impact of natural gas and oil price volatility onour cash flow from operations. Currently, we use a combination of fixed-priceswaps and NYMEX collars and put options to hedge natural gas and oil prices.Please read “Item 1—Operations— Hedging Activities” and “Item 7A—Quantitativeand Qualitative Disclosure About Market Risk.”

 

Our actual futureproduction may be significantly higher or lower than we estimate at the time weenter into hedging transactions for such period. If the actual amount ofproduction is higher than we estimate, we will have greater commodity priceexposure than we intended. If the actual amount of production is lower than thenotional amount that is subject to our derivative financial instruments, wemight be forced to satisfy all or a portion of our derivative transactionswithout the benefit of the cash flow from our sale or purchase of theunderlying physical commodity, resulting in a substantial diminution of ourliquidity. As a result of these factors, our hedging activities may not be aseffective as we intend in reducing the volatility of our cash flows, and incertain circumstances may actually increase the volatility of our cash flows.In addition, our hedging activities are subject to the following risks:

 

·      acounterparty may not perform its obligation under the applicable derivativeinstrument;

 

·      theremay be a change in the expected differential between the underlying commodityprice in the derivative instrument and the actual price received; and

 

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·      thesteps we take to monitor our derivative financial instruments may not detectand prevent violations of our risk management policies and procedures

 

***If the Asher lease is terminated or if Nami Resource LLC’srights to production under wells in which we have a contract right to receiveproceeds from the sale of production  are adversely affected, we couldlose our contract right to receive proceeds from the sale of production or it couldbe adversely affected.***

 

Nami Resources, LLC, asubsidiary of our Predecessor that was retained by Nami in connection with the Restructuringhas been involved in an ongoing dispute with Asher Land and Mineral Company,Ltd., or Asher, pursuant to which Asher claims that Nami Resources Company, LLCdid not correctly calculate the royalties paid to it and that it failed toabide by certain terms of the leases relating to the coordination of oil andgas development with coal development activities. As part of our separationfrom Vinland, we received from Nami Resources Company, LLC a contract right toreceive approximately 99% of the net proceeds, after deducting royalties paidto other parties, severance taxes, third-party transportation costs, costsincurred in the operation of wells and overhead costs, from the sale ofproduction from certain producing oil and gas wells located within the Asherlease, 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 NamiResources Company, LLC. If the Asher lease is terminated or if Nami ResourcesCompany, LLC rights to production under wells in which we have a contract rightto receive proceeds from the sale of production are adversely affected, wecould lose our contract right to receive proceeds from the sale of productionor it could be adversely affected.

 

***We are exposed to trade credit risk in theordinary course of our business activities.***

 

We are exposed to risksof loss in the event of nonperformance by our customers and by counterpartiesto our hedging arrangements. Some of our customers and counterparties may behighly leveraged and subject to their own operating and regulatory risks. Evenif our credit review and analysis mechanisms work properly, we may experiencefinancial losses in our dealings with other parties. Any increase in thenonpayment or nonperformance by our customers and/or counterparties couldreduce 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 theperformance of Scott W. Smith, our President and Chief Executive Officer,Richard A. Robert, our Executive Vice President and Chief Financial Officer andBritt Pence, our Vice President of Engineering. We maintain no key personinsurance for either Mr. Smith, Mr. Robert or Mr. Pence. Theloss of any or all of Messrs. Smith, Robert and Pence could negativelyimpact our ability to execute our strategy and our results of operations.

 

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

 

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

 

***We may be unable to compete effectively with largercompanies, which may adversely affect our ability to generate sufficientrevenue to allow us to pay distributions to our unitholders.***

 

The natural gas and oilindustry is intensely competitive, and we compete with other companies thathave greater resources. Our ability to acquire additional properties and todiscover reserves in the future will be dependent upon our ability to evaluateand select suitable properties and to consummate transactions in a highlycompetitive environment. Many of our larger competitors not only drill for andproduce natural gas and oil, but also carry on refining operations and marketpetroleum and other products on a regional, national or worldwide basis. These companiesmay be able to pay more for natural gas properties and evaluate, bid for andpurchase a greater number of properties than our financial or human resourcespermit.

 

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In addition, thesecompanies may have a greater ability to continue drilling activities duringperiods of low natural gas and oil prices and to absorb the burden of presentand future federal, state, local and other laws and regulations. Our inabilityto compete effectively with larger companies could have a material adverseimpact on our business activities, financial condition and results ofoperations.

 

***We are subject to complex federal, state, local and otherlaws and regulations that could adversely affect the cost, manner orfeasibility of doing business.***

 

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

 

Part of theregulatory environment in which we operate includes, in some cases, legalrequirements for obtaining environmental assessments, environmental impactstudies and/or plans of development before commencing drilling and productionactivities. In addition, our activities are subject to the regulationsregarding conservation practices and protection of correlative rights. Theseregulations affect our operations and limit the quantity of natural gas we mayproduce and sell. A major risk inherent in our drilling plans is the need toobtain drilling permits from state and local authorities. Delays in obtainingregulatory approvals or drilling permits, the failure to obtain a drillingpermit for a well or the receipt of a permit with unreasonable conditions orcosts could have a material adverse effect on our ability to develop ourproperties. Additionally, the natural gas and oil regulatory environment couldchange in ways that might substantially increase the financial and managerialcosts of compliance with these laws and regulations and, consequently,adversely affect our profitability. At this time, we cannot predict the effectof this increase on our results of operations. Furthermore, we may be put at acompetitive disadvantage to larger companies in our industry who can spreadthese additional costs over a greater number of wells and larger operatingstaff. Please read “Item1—Business—Operations—Environmental Matters andRegulation” and “Business—Operations—Other Regulation of the Natural Gas andOil 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 availablefor distribution.***

 

Higher natural gas pricesgenerally increase the demand for drilling rigs, supplies, services, equipmentand crews, and can lead to shortages of, and increasing costs for, drillingequipment, services and personnel. Over the past three years, we and othernatural gas and oil companies have experienced higher drilling and operatingcosts. Shortages of, or increasing costs for, experienced drilling crews andequipment and services could restrict our ability to drill the wells and conductthe operations that we currently have planned. Any delay in the drilling of newwells or significant increase in drilling costs could reduce our revenues andcash available for distribution.

 

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**Risks Related to Our Structure**

 

***Mr. Nami, who together with certain of his affiliatesand related persons, own approximately 27.1% of our outstanding common units,and certain members of our board of directors who are officers or directors ofVinland Energy Eastern may have conflicts of interest with us. The ultimateresolution of these conflicts of interest may result in favoring the interestsof these other parties over our unitholders’ and may be to our detriment. Ourlimited liability company agreement limits the remedies available to ourunitholders in the event  unitholdershave a claim relating to conflicts of interest.***

 

Two members of our boardof 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 onehand, and us and our unitholders, on the other hand. These potential conflictsmay relate to the divergent interests of these parties. Situations in which theinterests of Nami and his affiliates, including Vinland, and certain members ofour board of directors may differ from interests of owners of units include,among others, the following situations:

 
| · | our limited liability  company agreement gives our board of directors broad discretion in  establishing cash reserves for the proper conduct of our business, which will  affect the amount of cash available for distribution. For example, our board  of directors will use its reasonable discretion to establish and maintain  cash reserves sufficient to fund our drilling program;                                                                                                                                                                 |
|--------|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      |
| · | none of our limited  liability company agreement, management services agreement, participation  agreement  nor any other agreement requires Nami or any of his  affiliates, including Vinland, to pursue a business strategy that favors us.  Directors and officers of Vinland and its subsidiaries have a fiduciary duty  while acting in the capacity as such director or officer of Vinland or such  subsidiary to make decisions in the best interests of the members or  stockholders of Vinland, which may be contrary to our best interests; |
|   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      |
| · | we rely on Vinland to  operate and develop our properties in Appalachia;                                                                                                                                                                                                                                                                                                                                                                                                                                                                                  |
|   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      |
| · | we depend on Vinland to  gather, compress, deliver and provide services necessary for us to market our  natural gas production;                                                                                                                                                                                                                                                                                                                                                                                                                           |
|   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      |
| · | we intend to rely on  Vinland to provide us with opportunities for the acquisition of natural gas  and oil reserves, however, Vinland does not have an obligation to provide us  with such opportunities; and                                                                                                                                                                                                                                                                                                                                             |
|   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      |
| · | Nami and his  affiliates, including Vinland, are not prohibited from investing or engaging  in other businesses or activities that compete with us.                                                                                                                                                                                                                                                                                                                                                                                                       |

 

If in resolving conflictsof interest that exist or arise in the future our board of directors orofficers, as the case may be, satisfy the applicable standards set forth in ourlimited liability company agreement for resolving conflicts of interest,unitholders will not be able to assert that such resolution constituted abreach of fiduciary duty owed to us or to unitholders by our board of directorsand officers.

 

***We may issue additional units withoutunitholder approval, which would dilute their existing ownership interests.***

 

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

 

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

 
| · | the proportionate  ownership interest of unitholders in us may decrease;                 |
|--------|------------------------------------------------------------------------------------------|
|   |                                                                                     |
| · | the amount of cash  distributed on each unit may decrease;                               |
|   |                                                                                     |
| · | the relative voting  strength of each previously outstanding unit may be diminished; and |
|   |                                                                                     |
| · | the market price of the  units may decline.                                              |

 

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

 

Our limited liabilitycompany agreement restricts the voting rights of unitholders by providing thatany units held by a person that owns 20% or more of any class of units thenoutstanding, other than Nami and his affiliates or transferees and persons whoacquire such units with the prior approval of the board of directors, cannotvote on any matter. Our limited liability agreement also contains provisionslimiting the ability of unitholders to call meetings or to acquire informationabout our operations, as well as other provisions limiting unitholders’ abilityto influence the manner or direction of management.

 

***Our limited liability company agreement provides for alimited call right that may require unitholders to sell their units at anundesirable time or price.***

 

If, at any time, anyperson owns more than 90% of the units then outstanding, such person has theright, but not the obligation, which it may assign to any of its affiliates orto us, to acquire all, but not less than all, of the remaining units thenoutstanding at a price not less than the then-current market price of theunits. As a result, unitholders may be required to sell their units at anundesirable time or price and therefore may receive a lower or no return ontheir investment. Unitholders may also incur tax liability upon a sale of theirunits.

 

***The price of our common units could be subject to widefluctuations, unitholders could lose a significant part of their investment.***

 

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

 
| · | changes in securities  analysts’ recommendations and their estimates of our financial performance;                                                                                                                 |
|--------|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|   |                                                                                                                                                                                                                    |
| · | the public’s reaction  to our press releases, announcements and our filings with the SEC;                                                                                                                          |
|   |                                                                                                                                                                                                                    |
| · | fluctuations in broader  securities market prices and volumes, particularly among securities of  natural gas and oil companies and securities of publicly traded limited  partnerships and limited liability companies; |
|   |                                                                                                                                                                                                                    |
| · | changes in market  valuations of similar companies;                                                                                                                                                                     |
|   |                                                                                                                                                                                                                    |
| · | departures of key  personnel;                                                                                                                                                                                           |
|   |                                                                                                                                                                                                                    |
| · | commencement of or  involvement in litigation;                                                                                                                                                                          |
|   |                                                                                                                                                                                                                    |
| · | variations in our  quarterly results of operations or those of other natural gas and oil  companies;                                                                                                                    |
|   |                                                                                                                                                                                                                    |
| · | variations in the  amount of our quarterly cash distributions;                                                                                                                                                          |
|   |                                                                                                                                                                                                                    |
| · | future issuances and  sales of our units; and                                                                                                                                                                           |
|   |                                                                                                                                                                                                                    |
| · | changes in general  conditions in the U.S. economy, financial markets or the natural gas and oil  industry.                                                                                                             |

 

In recent years, thesecurities market has experienced extreme price and volume fluctuations. Thisvolatility has had a significant effect on the market price of securitiesissued by many companies for reasons unrelated to the operating performance ofthese companies. Future market fluctuations may result in a lower price of ourcommon units.

 

***Unitholders may have liability to repaydistributions.***

 

Under certaincircumstances, unitholders may have to repay amounts wrongfully returned ordistributed to them. Under Section 18-607 of the Delaware Revised LimitedLiability Company Act, or the “Delaware Act”, we may not make a distribution tounitholders if the distribution would cause our liabilities to exceed the fairvalue of our assets. Delaware law provides that for a period of three yearsfrom the date of an impermissible distribution, members or unitholders whoreceived the distribution and who knew at the time of the distribution that itviolated Delaware law will be liable to the limited liability company for thedistribution amount.

 

28

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A purchaser of commonunits who becomes a member or unitholder is liable for the obligations of thetransferring member to make contributions to the limited liability company thatare known to such purchaser of units at the time it became a member and forunknown obligations if the liabilities could be determined from our limitedliability company agreement.

 

***An increase in interest rates may cause themarket price of our common units to decline.***

 

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

 

**Tax Risks to Unitholders**

 

***Our tax treatment depends on our status as a partnership forfederal income tax purposes, as well as our not being subject to a materialamount of entity-level taxation by individual states. If the IRS were to treatus as a corporation for federal income tax purposes or we were to becomesubject to additional amounts of entity-level taxation for state tax purposes,taxes paid, if any, would reduce the amount of cash available for distributionto unitholders.***

 

The anticipated after-taxeconomic benefit of an investment in our units depends largely on our beingtreated as a partnership for federal income tax purposes. We have notrequested, and do not plan to request, a ruling from the IRS on this or anyother tax matter that affects us.

 

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

 

If we were treated as acorporation for federal income tax purposes, we would pay federal income tax onour taxable income at the corporate tax rates, currently at a maximum rate of35%, and would likely pay state income tax at varying rates. Distributions tounitholders would generally be taxed again as corporate distributions, and noincome, gain, loss, deduction or credit would flow through to unitholders.Because a tax may be imposed on us as a corporation, our cash available fordistribution to our unitholders could be reduced. Therefore, treatment of us asa corporation would result in a material reduction in the anticipated cash flowand after-tax return to our unitholders, likely causing a substantial reductionin the value of our common units.

 

Current law or ourbusiness may change so as to cause us to be treated as a corporation forfederal income tax purposes or otherwise subject us to entity-level taxation.At the federal level, legislation has been proposed that would eliminatepartnership tax treatment for certain publicly traded LLCs.  Although such legislation would not apply tous as currently proposed, it could be amended prior to enactment in a mannerthat does apply to us.  We are unable topredict whether any of these changes or other proposals will ultimately beenacted.  Moreover, any modification tothe federal income tax laws and interpretations thereof may or may not be appliedretroactively.  Any such changes couldnegatively impact the value of an investment in our units.  At the state level, because of widespreadstate budget deficits and other reasons, several states are evaluating ways tosubject partnerships and limited liability companies to entity-level taxationthrough the imposition of state income, franchise or other forms oftaxation.   For example, we are requiredto pay Texas franchise tax at a maximum effective rate of 0.7% of our grossincome apportioned to Texas in the prior year. If any other state were to impose a tax upon us as an entity, the cashavailable for distribution to unitholders would be reduced.

 

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

 

We have not requested aruling from the IRS with respect to our treatment as a partnership for federalincome tax purposes or any other matter that affects us.

 

29

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The IRS may adoptpositions that differ from the positions we take. It may be necessary to resortto administrative or court proceedings to sustain some or all of the positionswe take and a court may disagree with some or all of those positions. Anycontest with the IRS may materially and adversely impact the market for ourunits and the price at which they trade. In addition, our costs of any contestwith the IRS will result in a reduction in cash available for distribution toour unitholders and thus will be borne indirectly by our unitholders.

 

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

 

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

 

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

 

If unitholders sell theircommon units, they will recognize a gain or loss equal to the differencebetween the amount realized and their tax basis in those common units. Becausedistributions in excess of a unitholder’s allocable share of our net taxableincome decreases the tax basis in the unitholder’s common units, the amount, ifany, of such prior excess distributions with respect to the units they sellwill, in effect, become taxable income to them if they sell such units at aprice greater than their tax basis in those units, even if the price theyreceive is less than their original cost. Furthermore, a substantial portion ofthe amount realized, whether or not representing gain, may be taxed as ordinaryincome due to potential recapture items, including depreciation recapture. Inaddition, because the amount realized includes a unitholder’s share of ournonrecourse liabilities, if a unitholders sells their units, they may incur atax liability in excess of the amount of cash they receive from the sale.

 

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

 

Investment in units bytax-exempt entities, including employee benefit plans and individual retirementaccounts (known as IRAs), and non-U.S. persons raises issues unique to them.For example, virtually all of our income allocated to organizations exempt fromfederal income tax, including IRAs and other retirement plans, will beunrelated business taxable income and will be taxable to such a unitholder.Distributions to non-U.S. persons will be reduced by withholding taxes imposedat the highest effective applicable tax rate, and non-U.S. persons will berequired to file United States federal income tax returns and pay tax on theirshare 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 thesame tax benefits without regard to the actual units purchased. The IRS maychallenge this treatment, which could adversely affect the value of the commonunits.***

 

Because we cannot matchtransferors and transferees of common units and because of other reasons, wewill adopt depreciation and amortization positions that may not conform withall aspects of existing Treasury Regulations. A successful IRS challenge tothose positions could adversely affect the amount of tax benefits available toour unitholders. It also could affect the timing of these tax benefits or theamount of gain on the sale of common units and could have a negative impact onthe value of our common units or result in audits of and adjustments to ourunitholders’ tax returns.

 

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

### ** **

  We prorate our items of income, gain, lossand deduction between transferors and transferees of our units each month basedupon the ownership of our units on the first day of each month, instead of onthe basis of the date a particular unit is transferred. The use of thisproration method may not be permitted under existing Treasury Regulations. Ifthe 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 anddeduction among our unitholders.

 

30

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### ***A unitholder whose units are loaned to a “shortseller” to cover a short sale of units may be considered as having disposed ofthose units. If so, he would no longer be treated for tax purposes as a partnerwith respect to those units during the period of the loan and may recognizegain or loss from the disposition.***

 

Because a unitholderwhose units are loaned to a “short seller” to cover a short sale of units maybe considered as having disposed of the loaned units, he may no longer betreated for tax purposes as a partner with respect to those units during theperiod of the loan to the short seller and the unitholder may recognize gain orloss from such disposition. Moreover, during the period of the loan to theshort seller, any of our income, gain, loss or deduction with respect to thoseunits may not be reportable by the unitholder and any cash distributionsreceived by the unitholder as to those units could be fully taxable as ordinaryincome. Unitholders desiring to assure their status as partners and avoid therisk of gain recognition from a loan to a short seller are urged to modify anyapplicable brokerage account agreements to prohibit their brokers fromborrowing their units.

 

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

 

We will be considered tohave terminated for federal income tax purposes if there is a sale or exchangeof 50% or more of the total interests in our capital and profits within atwelve-month period. Our termination would, among other things, result in theclosing of our taxable year for all unitholders, which would result in usfiling two tax returns (and our unitholders could receive two Schedules K-1)for one fiscal year and could result in a deferral of depreciation deductionsallowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscalyear ending December 31, the closing of our taxable year may also resultin more than twelve months of our taxable income or loss being includable inhis taxable income for the year of termination. Our termination currently would not affect our classification as apartnership for federal income tax purposes. If treated as a new partnership, we must make new tax election and couldbe subject to penalties if we are unable to determine that a terminationoccurred.

 

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

 

In addition to federalincome taxes, you will likely be subject to other taxes, including foreign,state and local taxes, unincorporated business taxes and estate, inheritance orintangible taxes that are imposed by the various jurisdictions in which weconduct business or own property now or in the future, even if you do not livein any of those jurisdictions.  You willlikely be required to file foreign, state and local income tax returns and paystate and local income taxes in some or all of these variousjurisdictions.  Further, you may besubject to penalties for failure to comply with those requirements.  We currently own property and conduct businessin Kentucky, New Mexico, Tennessee and Texas. Each of these states, other than Texas, imposes an income tax onindividuals.  Most of these states alsoimpose 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 apersonal income tax.  It is yourresponsibility to file all United States federal, foreign, state and local taxreturns.

 

**ITEM 1B.     UNRESOLVEDSTAFF COMMENTS**

 

None.

 

**ITEM 2.     PROPERTIES**

 

A description of ourproperties is included in Part I, Item 1, Business, and isincorporated herein by reference.

 

We believe that we havesatisfactory title to the properties owned and used in our businesses, subjectto liens for taxes not yet payable, liens incident to minor encumbrances, liensfor credit arrangements and easements and restrictions that do not materiallydetract from the value of these properties, our interests in these properties,or the use of these properties in our businesses. We believe that ourproperties are adequate and suitable for the conduct of our business in thefuture.

 

31

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**ITEM 3.     LEGALPROCEEDINGS**

 

Although we may, fromtime to time, be involved in litigation and claims arising out of ouroperations in the normal course of business, we are not currently a party toany material legal proceedings. In addition, we are not aware of any legal orgovernmental 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 connectionwith the Restructuring, has been involved in an ongoing dispute with Asher Landand Mineral Company, Ltd., or Asher, pursuant to which Asher claims that NamiResources Company, LLC did not correctly calculate the royalties paid to it andthat it failed to abide by certain terms of the leases relating to thecoordination 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 ResourcesCompany, LLC,* Bell Circuit Court, Civil Action No. 06-CI-00417.In that action, Asher sought damages and rescission of the leases. Before aresponsive pleading was filed, Asher voluntarily withdrew its complaint anddismissed that action. On December 15, 2006, Asher filed a new actionstyled* Asher Land and Mineral, Ltd. v. Nami Resources Company, LLC* ,Bell Circuit Court, Civil Action No. 06-CI-00566. In that action, Asherhas made the same allegations as in the prior suit and added a claim for anundetermined amount of punitive damages. The parties have exchanged discoveryrequests.

 

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 severalmotions to be dismissed from this action but to date is still a named defendantin this case. We have retained separate counsel to monitor this case as itprogresses.

 

In connection with theRestructuring, we received a contract right to receive approximately 99% of thenet proceeds from the sale of production from certain producing oil and gaswells located within the Asher lease, which accounted for approximately 4.5% ofour estimated proved reserves as of December 31, 2007. We did not receivean assignment of any working interest in the Asher lease. The Asher lease andthe litigation related thereto were retained by Nami Resources Company, LLC. Ifthe Asher lease is terminated or if Nami Resources Company, LLC’  rights to production under wells of which wehave contract rights to receive proceeds are adversely affected, we could loseour contract rights to receive such proceeds or it could be adversely affected.

 

In connection with theRestructuring, Nami Resources Company, LLC and Vinland have agreed to indemnifyus for all liabilities, judgments and damages that may arise in connection withthe litigation referenced above as well as providing for the defense of anysuch claims.  The indemnities agreed to by NamiResources Company, LLC and Vinland will remain in place until the resolution ofthe Asher litigation.

 
| **ITEM 4.** | **SUBMISSION  OF MATTERS TO A VOTE OF SECURITY HOLDERS** |
|------------------|----------------------------------------------------------|

 

None.

 

32

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**PART II**

 
| **ITEM 5.** | ** ** | **MARKET  FOR REGISTRANT’S COMMON UNITS, RELATED STOCKHOLDER MATTERS AND ISSUER  PURCHASES OF EQUITY SECURITIES** |
|------------------|------------|------------------------------------------------------------------------------------------------------------------------|

 

Our common units aretraded on the NYSE Arca, Inc. under the symbol “VNR”. Our units begantrading on October 24, 2007, in connection with our IPO. On March 12,2008, there were 10,795,000 common units outstanding and approximately twelveunitholders, which does not include beneficial owners whose units are held by aclearing agency, such as a broker or a bank. On March 12, 2008, the marketprice for our common units was $15.88 per unit, resulting in an aggregatemarket value of units held by non-affiliates of approximately$171,424,600.  The following tablepresents the high and low sales price for our common units during the periodsindicated.

 
| ** **     | ** ** | **Common Units** | ** ** |
|----------------|------------|-----------------------|------------|
| ** **     | ** ** | **High**              | ** ** | **Low** | ** ** |
| **2007**       | ** ** | ** **            | ** ** | ** ** | ** ** |
| Fourth Quarter |       | $                     | 19.15      |   | $ | 14.12 |   |
|                |            |                       |            |  |  |  |  |

 

*StockPerformance Graph.*Theperformance graph below compares total unitholder return on our units, with thetotal 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 energypublicly traded partnerships. Total return includes the change in the marketprice, adjusted for reinvested dividends or distributions, for the period shownon the performance graph and assumes that $100 was invested in VNR at the lastreported 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 ourpeer group index on the same date.  Theresults shown in the graph below are not necessarily indicative of futureperformance.

 

 
| ** **                       | ** ** | **October 24, 2007** | ** ** | **December 31, 2007** | ** ** |
|----------------------------------|------------|--------------------------------|------------|---------------------------------|------------|
| Vanguard Natural  Resources, LLC |       | $                              | 100        |                            | $          | 84.48 | (1) |
| Peer Group Index                 |       | $                              | 100        |                            | $          | 90.66 |   |
| S&P 500  Index               |       | $                              | 100        |                            | $          | 95.15 |   |

 

----

| (1) | Based  on the last reported sale price of VNR units as reported by NYSE  Arca, Inc. on December 31, 2007 ($16.00). |
|-----|------------------------------------------------------------------------------------------------------------------------------|

 

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*DistributionsDeclared.* Thefollowing table shows the amount per unit, record date and payment date of thequarterly cash distributions we paid on each of our common units for eachperiod presented. Future distributions are at the discretion of our board ofdirectors and will depend on business conditions, earnings, our cashrequirements and other relevant factors.

 
| ** **    | ** ** | **Cash Distributions** | ** ** |
|---------------|------------|-----------------------------|------------|
| ** **    | ** ** | **Per Unit**           | ** ** | **Record Date** | ** ** | **Payment Date** | ** ** |
| **2008**      |       |                        |       |   |   |   |   |
| First Quarter |       | $                           | 0.425      | (1) | February 7, 2008 |   | February 14, 2008 |   |
|               |            |                             |            |  |  |  |  |  |

 

----

| (1) | This  distribution was pro-rated for the period from the closing of the IPO on  October 29, 2007 through December 31, 2007, resulting in a  distribution of $0.291 per unit for the period. |
|-----|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|

 

Our limited liabilitycompany agreement requires that, within 45 days after the end of each quarter,beginning with the quarter ended December 31, 2007, we distribute all ofour 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:

 
|   | (i)    | all our and our  subsidiaries’ cash and cash equivalents (or our proportionate share of cash  and cash equivalents in the case of subsidiaries that are not wholly owned)  on hand at the end of that quarter; and                                                                                                                                    |
|--------|--------|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|   |   |                                                                                                                                                                                                                                                                                                                                                       |
|   | (ii)   | all our and our  subsidiaries’ additional cash and cash equivalents (or our proportionate  share of cash and cash equivalents in the case of subsidiaries that are not  wholly owned) on hand on the date of determination of available cash for that  quarter resulting from working capital borrowings made subsequent to the end  of such quarter, |

 

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

 
|   | (i)    | provide for the proper  conduct of our or our subsidiaries’ business (including reserves for future  capital expenditures, including drilling and acquisitions, and for our and  our subsidiaries’ anticipated future credit needs), |
|--------|--------|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|   |   |                                                                                                                                                                                                                                           |
|   | (ii)   | comply with applicable  law or any loan agreement, security agreement, mortgage, debt instrument or  other agreement or obligation to which we or any of our subsidiaries is a  party or by which we are bound or our assets are subject; or   |
|   |   |                                                                                                                                                                                                                                           |
|   | (iii)  | provide funds for  distributions to our unitholders with respect to any one or more of the next  four quarters;                                                                                                                                |

 

provided thatdisbursements 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 ofdetermination of available cash for that quarter shall be deemed to have beenmade, established, increased or reduced, for purposes of determining availablecash, within that quarter if the board of directors so determines.

 

**Use of Proceeds**

 

Our IPO of common unitsrepresenting 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. Wecompleted our IPO of 5,250,000 common units representing limited liabilitycompany 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 IPOwere used to reduce indebtedness under our Credit Facility by $80.0 million andthe balance was used for the payment of accrued distributions to pre-IPO unitholdersand the payment of a deferred swap obligation.

 

All proceeds receivedfrom our IPO have been applied.

 

34

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**ITEM 6.  SELECTED FINANCIAL DATA**

 

Set forth below is oursummary of our consolidated financial and operating data for the periodsindicated for Vanguard Natural Resources, LLC and our Predecessor. Thehistorical financial data for the years ended December 31, 2004, 2005 and2006 and the balance sheet data as of December 31, 2004, 2005 and 2006have been derived from the audited financial statements of our Predecessor. Thehistorical financial data for the year ended December 31, 2003 and thebalance sheet as of December 31, 2003 are derived from the unauditedfinancial statements of our Predecessor. Please read “Item 7, Management’sDiscussion and Analysis of Financial Condition and Results ofOperations—Comparability of Financials Statements” for the reasons why thehistorical financial statements of our Predecessor included in this AnnualReport on Form 10-K may not be comparable to our results of operations.

 

The selected financialdata should be read together with Part II, Item 7, Management’sDiscussion and Analysis of Financial Condition and Results of Operations and Part II,Item 8, Financial Statements and Supplementary Data included in thisReport on Form 10-K.

 

The following tablepresents a non-GAAP financial measure, adjusted EBITDA, which we use in ourbusiness. This measure is not calculated or presented in accordance withgenerally accepted accounting principles, or GAAP. We explain this measurebelow and reconcile it to the most directly comparable financial measurecalculated and presented in accordance with GAAP in “Non-GAAP FinancialMeasure.”

 
| ** **                                       | ** ** | **Year Ended December 31,** | ** ** |
|--------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                       | ** ** | **(in thousands)**                    | ** ** |
| ** **                                       | ** ** | **Vanguard**                               | ** ** | **Vanguard  Predecessor** | ** ** |
| ** **                                       | ** ** | **2007**                                   | ** ** | **2006** | ** ** | **2005** | ** ** | **2004** | ** ** | **2003** | ** ** |
| ** **                                       | ** ** | ** **                                 | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | **(unaudited)** | ** ** |
| **Statement  of Operations Data:**               |       |                                       |       |   |   |   |   |   |   |   |   |
| **Revenues:**                                    |       |                                       |       |   |   |   |   |   |   |   |   |
| Natural gas and  oil sales                       |       | $                                          | 34,541     |   | $ | 38,184 |   | $ | 40,299 |   | $ | 23,881 |   | $ | 17,844 |   |
| Realized losses  on derivative contracts         |       | (702                                       | )          | (2,208 | ) | (10,024 | ) | (5,926 | ) | (1,939 | ) |
| Change in fair  value of derivative contracts(1) |       | —                                     |       | 17,748 |   | (18,779 | ) | (991 | ) | — |   |
| Other                                            |       | —                                     |       | 665 |   | 451 |   | 29 |   | 83 |   |
| Total revenues                                   |       | 33,839                                     |       | 54,389 |   | 11,947 |   | 16,993 |   | 15,988 |   |
| **Costs  and Expenses:**                         |       |                                       |       |   |   |   |   |   |   |   |   |
| Lease operating  expenses                        |       | 5,066                                      |       | 4,896 |   | 4,607 |   | 2,407 |   | 2,126 |   |
| Depreciation,  depletion and amortization        |       | 8,981                                      |       | 8,633 |   | 6,189 |   | 4,029 |   | 3,109 |   |
| Selling, general  and administrative             |       | 3,507                                      | (2)        | 5,199 |   | 5,946 |   | 3,154 |   | 3,454 |   |
| Bad debt expense                                 |       | 1,007                                      |       | — |   | — |   | — |   | — |   |
| Taxes other than  income                         |       | 2,054                                      |       | 1,774 |   | 1,249 |   | 611 |   | 505 |   |
| Total costs and  expenses                        |       | 20,615                                     |       | 20,502 |   | 17,991 |   | 10,201 |   | 9,194 |   |
| **Income  (Loss) from Operations:**              |       | 13,224                                     |       | 33,887 |   | (6,044 | ) | 6,792 |   | 6,794 |   |
| **Other  Income and (Expenses):**                |       |                                       |       |   |   |   |   |   |   |   |   |
| Interest income                                  |       | 62                                         |       | 40 |   | 52 |   | 7 |   | 14 |   |
| Interest and  financing expenses                 |       | (8,135                                     | )          | (7,372 | ) | (4,566 | ) | (1,455 | ) | (1,413 | ) |
| Loss on  extinguishment of debt                  |       | (2,502                                     | )          | — |   | — |   | — |   | — |   |
| Total other  income and (expenses)               |       | (10,575                                    | )          | (7,332 | ) | (4,514 | ) | (1,448 | ) | (1,399 | ) |
| **Net  income (loss)**                           |       | $                                          | 2,649      |   | $ | 26,555 |   | $ | (10,558 | ) | $ | 5,344 |   | $ | 5,395 |   |
| **Cash  Flow Data:**                             |       |                                       |       |   |   |   |   |   |   |   |   |
| Net cash  provided by operating activities(1)    |       | $                                          | 1,372      |   | $ | 16,087 |   | $ | 10,530 |   | $ | 9,607 |   | $ | 7,058 |   |
| Net cash used in  investing activities           |       | (26,409                                    | )          | (37,383 | ) | (37,068 | ) | (19,598 | ) | (10,641 | ) |
| Net cash  provided by financing activities       |       | 26,415                                     |       | 19,985 |   | 25,571 |   | 12,721 |   | (500 | ) |
| **Other  Financial Information (unaudited):**    |       |                                       |       |   |   |   |   |   |   |   |   |
| Adjusted EBITDA(3)                               |       | $                                          | 30,395     |   | $ | 24,772 |   | $ | 18,924 |   | $ | 11,812 |   | $ | 9,903 |   |

 

35

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| ** **                                                                                   | ** ** | **As of December 31,** | ** ** |
|----------------------------------------------------------------------------------------------|------------|---------------------------------------|------------|
| ** **                                                                                   | ** ** | **(in thousands)**               | ** ** |
| ** **                                                                                   | ** ** | **Vanguard**                          | ** ** | **Vanguard  Predecessor** | ** ** |
| ** **                                                                                   | ** ** | **2007**                              | ** ** | **2006** | ** ** | **2005** | ** ** | **2004** | ** ** | **2003** | ** ** |
| ** **                                                                                   | ** ** | ** **                            | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | **(unaudited)** | ** ** |
| **Balance  Sheet Data:**                                                                     |       |                                  |       |   |   |   |   |   |   |   |   |
| Cash and cash  equivalents                                                                   |       | $                                     | 3,110      |   | $ | 1,731 |   | $ | 3,041 |   | $ | 4,009 |   | $ | 1,279 |   |
| Short-term  derivative assets                                                                |       | 4,017                                 |       | — |   | — |   | — |   | — |   |
| Other current  assets                                                                        |       | 4,826                                 |       | 20,438 |   | 19,598 |   | 10,033 |   | 6,473 |   |
| Natural gas and  oil properties, net of accumulated depreciation, depletion and amortization |       | 106,983                               |       | 104,684 |   | 83,513 |   | 54,761 |   | 39,555 |   |
| Property, plant  and equipment, net of accumulated depreciation                              |       | 166                                   |       | 11,873 |   | 4,104 |   | 1,894 |   | 1,480 |   |
| Long-term  derivative assets                                                                 |       | 1,330                                 |       | — |   | — |   | — |   | — |   |
| Other assets                                                                                 |       | 10,747                                |       | — |   | — |   | — |   | — |   |
| Total assets                                                                                 |       | $                                     | 131,179    |   | $ | 138,726 |   | $ | 110,256 |   | $ | 70,697 |   | $ | 48,787 |   |
| Short-term  derivative liabilities                                                           |       | $                                     | —     |   | $ | 2,022 |   | $ | 11,527 |   | $ | 800 |   | — |   |
| Other current  liabilities                                                                   |       | 5,355                                 |       | 11,505 |   | 12,033 |   | 6,347 |   | 3,545 |   |
| Long-term debt                                                                               |       | 37,400                                |       | 94,068 |   | 72,708 |   | 42,318 |   | 28,318 |   |
| Long-term  derivative liabilities                                                            |       | 5,903                                 |       | — |   | 8,243 |   | 191 |   | — |   |
| Other long-term  liabilities                                                                 |       | 190                                   |       | 418 |   | 212 |   | 130 |   | 78 |   |
| Members’ capital                                                                        |       | 82,331                                |       | 30,713 |   | 5,533 |   | 20,911 |   | 16,846 |   |
| Total  liabilities and members’ capital                                                 |       | $                                     | 131,179    |   | $ | 138,726 |   | $ | 110,256 |   | $ | 70,697 |   | $ | 48,787 |   |

 

----

| (1)    | Natural  gas derivative contracts were used to reduce our exposure to changes in  natural gas prices. Prior to 2007, they were not specifically designated as  hedges under Statement of Financial Accounting Standards (SFAS) No. 133.  Change in the fair value of these natural gas derivative contracts were  marked to market in our earnings prior to 2007. In 2007, we designated as  hedges and thus changes in fair value in 2007 are included in other  comprehensive income (loss). Further, these amounts represent non-cash  charges. |
|--------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    |   |
| (2)    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    | Includes  $2.1 million of non-cash compensation expense. |
|   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    |   |
| (3)    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    | See  “Non-GAAP Financial Measure” below. |

 

**SummaryReserve and Operating Data**

 

The following tables showestimated net proved reserves based on a reserve report prepared by ourindependent petroleum engineers, NSAI, and certain summary unauditedinformation with respect to our production and sales of natural gas and oil.You should refer to “Item 1A—Risk Factors,” “Item 7—Management’s Discussion andAnalysis of Financial Condition and Results of Operations,” “Item1—Business—Natural Gas and Oil Data—Proved Reserves” and “—Production and PriceHistory” and the reserve report included in this Annual report on Form 10-Kin evaluating the material presented below.

 

36

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| ** **                                               | ** ** | **As of  December 31,  2007** | ** ** |
|----------------------------------------------------------|------------|-----------------------------------------|------------|
| **Reserve Data:**                                   |       |                                    |       |
| Estimated net proved reserves:            |       |                                    |       |
| Natural gas  (Bcf)                                       |       | 65.1                                    |       |
| Crude oil  (MBbls)                                       |       | 336                                     |       |
| Total (Bcfe)                                             |       | 67.1                                    |       |
| Proved developed  (Bcfe)                                 |       | 50.3                                    |       |
| Proved  undeveloped (Bcfe)                               |       | 16.8                                    |       |
| Proved developed  reserves as % of total proved reserves |       | 75                                      | %          |
| **Standardized  Measure (in millions)****(1)**           |       | $                                       | 151.0      |   |
| **Representative  Natural Gas and Oil Prices:**          | ** ** | ** **                              | ** ** |
| Natural gas—spot  Henry Hub per MMBtu               |       | $                                       | 6.79       |   |
| Oil—spot WTI per  Bbl                               |       | $                                       | 92.50      |   |

 
| ** **                                            | ** ** | **Year Ended December 31,** | ** ** |
|-------------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                            | ** ** | **Vanguard**                               | ** ** | **Vanguard  Predecessor** | ** ** |
| ** **                                            | ** ** | **2007**                                   | ** ** | **2006** | ** ** | **2005** | ** ** |
| **Net Production:**                              | ** ** | ** **                                 | ** ** | ** ** | ** ** | ** ** | ** ** |
| Total realized  production (MMcfe)                    |       | 4,238                                      |       | 4,378 |   | 3,894 |   |
| Average daily  production (Mcfe/d)                    |       | 11,610                                     |       | 11,995 |   | 10,669 |   |
|                                                  |       |                                       |       |   |   |   |   |
| **Average  Realized Sales Prices ($ per Mcfe):** |       |                                       |       |   |   |   |   |
| Average realized  sales prices (including hedges)     |       | $                                          | 8.99       | (2) | $ | 8.22 |   | $ | 7.77 |   |
| Average realized  sales prices (excluding hedges)     |       | $                                          | 8.15       |   | $ | 8.72 |   | $ | 10.35 |   |
| **Average  Unit Costs ($ per Mcfe):**            |       |                                       |       |   |   |   |   |
| Production costs(3)                                   |       | $                                          | 1.68       |   | $ | 1.52 |   | $ | 1.50 |   |
| Selling, general  and administrative expenses         |       | $                                          | 0.83       | (4) | $ | 1.19 |   | $ | 1.53 |   |
| Depreciation,  depletion and amortization             |       | $                                          | 2.12       |   | $ | 1.97 |   | $ | 1.59 |   |

 

----

| (1)    |   | Standardized  Measure is the present value of estimated future net revenues to be generated  from the production of proved reserves, determined in accordance with the  rules and regulations of the Securities and Exchange Commission (using  prices and costs in effect as of the date of estimation) without giving  effect to non-property related expenses such as selling, general and  administrative expenses, debt service and future income tax expenses or to  depreciation, depletion and amortization and discounted using an annual  discount rate of 10%. Our Standardized Measure does not include future income  tax expenses because our reserves are owned by our subsidiary Vanguard  Natural Gas, LLC which is not subject to income taxes. Standardized Measure  does not give effect to derivative transactions. For a description of our  derivative transactions, please read “Item 7—Management’s Discussion and  Analysis of Financial Condition and Results of Operations—Cash Flow from  Operations.” |
|--------|--------|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|   |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              |
| (2)    |   | Excludes  premiums paid on settled derivatives.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                   |
|   |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              |
| (3)    |   | Production  costs include such items as lease operating expenses, production taxes  (severance and ad valorem taxes) as well as gathering and compression fees  and other customary charges.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      |
|   |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              |
| (4)    |   | Includes  $2.1 million ($0.51/Mcfe) of non-cash compensation expense.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                             |

 

37

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**Non-GAAPFinancial Measure**

 

**Adjusted EBITDA**

 

We define Adjusted EBITDAas net income (loss) plus:

 
| · | Net interest expense  (including write-off of deferred financing fees);                          |
|--------|--------------------------------------------------------------------------------------------------|
|   |                                                                                             |
| · | Loss on extinguishment  of debt;                                                                 |
|   |                                                                                             |
| · | Depreciation, depletion  and amortization (including accretion of asset retirement obligations); |
|   |                                                                                             |
| · | Bad debt expenses;                                                                               |
|   |                                                                                             |
| · | Premiums paid on  settled derivatives;                                                           |
|   |                                                                                             |
| · | Change in fair value of  derivative contracts                                                    |
|   |                                                                                             |
| · | Unit-based compensation  expense; and                                                            |
|   |                                                                                             |
| · | Realized (gain) loss on  cancelled derivatives.                                                  |

 

Adjusted EBITDA is asignificant performance metric used by our management to indicate (prior to theestablishment of any cash reserves by our board of directors) the cashdistributions we expect to pay our unitholders. Specifically, this financialmeasure indicates to investors whether or not we are generating cash flow at alevel that can sustain or support an increase in our quarterly distributionrates. Adjusted EBITDA is also a quantitative standard used throughout theinvestment community with respect to publicly-traded partnerships and limitedliability companies.

 

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

 

The following tablepresents a reconciliation of our consolidated net income (loss) to adjustedEBITDA:

 
| ** **                                       | ** ** | **Year Ended December 31,** | ** ** |
|--------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                       | ** ** | **(in thousands)**                    | ** ** |
| ** **                                       | ** ** | **Vanguard**                               | ** ** | **Vanguard  Predecessor** | ** ** |
| ** **                                       | ** ** | **2007**                                   | ** ** | **2006** | ** ** | **2005** | ** ** | **2004** | ** ** | **2003** | ** ** |
| ** **                                       | ** ** | ** **                                 | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | **(unaudited)** | ** ** |
| Net income  (loss)                               |       | $                                          | 2,649      |   | $ | 26,555 |   | $ | (10,558 | ) | $ | 5,344 |   | $ | 5,395 |   |
| Plus:                                            |       |                                       |       |   |   |   |   |   |   |   |   |
| Interest expense                                 |       | 8,135                                      |       | 7,372 |   | 4,566 |   | 1,455 |   | 1,413 |   |
| Loss on  extinguishment of debt                  |       | 2,502                                      |       | — |   | — |   | — |   | — |   |
| Depreciation,  depletion and amortization        |       | 8,981                                      |       | 8,633 |   | 6,189 |   | 4,029 |   | 3,109 |   |
| Bad debt expense                                 |       | 1,007                                      |       | — |   | — |   | — |   | — |   |
| Premiums paid on  settled derivatives            |       | 4,274                                      |       | — |   | — |   | — |   | — |   |
| Change in fair  value of derivative contracts(1) |       | —                                     |       | (17,748 | ) | 18,779 |   | 991 |   | — |   |
| Unit-based  compensation expense                 |       | 2,132                                      |       | — |   | — |   | — |   | — |   |
| Realized loss on  cancelled derivatives          |       | 777                                        |       | — |   | — |   | — |   | — |   |
| Less:                                            |       |                                       |       |   |   |   |   |   |   |   |   |
| Interest income                                  |       | 62                                         |       | 40 |   | 52 |   | 7 |   | 14 |   |
| Adjusted EBITDA                                  |       | $                                          | 30,395     |   | $ | 24,772 |   | $ | 18,924 |   | $ | 11,812 |   | $ | 9,903 |   |

 

----

| (1) | Natural  gas derivative contracts were used to reduce our exposure to changes in  natural gas prices. Prior to 2007, they were not specifically designated as  hedges under Statement of Financial Accounting Standards (SFAS) No. 133.  Change in the fair value of these natural gas derivative contracts are marked  to market in our earnings each period. Further, these amounts represent  non-cash charges. |
|-----|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|

 

38

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| **ITEM 7.** | ** ** | **MANAGEMENT’S  DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS** |
|------------------|------------|-------------------------------------------------------------------------------------------------|

 

*Thefollowing discussion and analysis should be read in conjunction with “Item 6 –Selected Financial Data” and the accompanying financial statements and relatednotes included elsewhere in this Annual Report on Form 10-K. The followingdiscussion contains forward-looking statements that reflect our future plans,estimates, forecasts, guidance, beliefs and expected performance. Theforward-looking statements are dependent upon events, risks and uncertaintiesthat may be outside our control. Our actual results could differ materiallyfrom those discussed in these forward-looking statements. Factors that couldcause or contribute to such differences include, but are not limited to, marketprices for natural gas, production volumes, estimates of proved reserves,capital expenditures, economic and competitive conditions, regulatory changesand other uncertainties, as well as those factors discussed below and elsewherein this Annual Report on Form 10-K, particularly in “Item 1A –Risk Factors”and “Forward Looking Statements,” all of which are difficult to predict. Inlight of these risks, uncertainties and assumptions, the forward-looking eventsdiscussed may not occur*.

 

**Overview**

 

We are a publicly tradedlimited liability company focused on the acquisition, development andexploitation of mature, long-lived natural gas and oil properties. Our primarybusiness objective is to generate stable cash flows allowing us to makequarterly cash distributions to our unitholders and over time to increase ourquarterly cash distributions through the acquisition of new natural gas and oilproperties. As of December 31, 2007, our properties are located in thesouthern portion of the Appalachian Basin, primarily in southeast Kentucky andnortheast Tennessee. Subsequent to December 31, 2007, we acquired newnatural gas and oil properties as discussed in Permian Basin Acquisition below.

 

We owned workinginterests in 943 gross (825 net) productive wells at December 31, 2007 andour average net production for the year ended December 31, 2007 was 11,610Mcfe per day. We also have 40% of our Predecessor’s working interest in theknown producing horizons in approximately 104,000 gross undeveloped acressurrounding or adjacent to our existing wells located in southeast Kentucky andnortheast Tennessee. Vinland Energy Operations, LLC (“Vinland”) acts as theoperator of our existing wells in Appalachia and all of the wells that we willdrill in this area.

 

***Initial Public Offering***

 

In October 2007, wecompleted our IPO of 5.25 million units representing limited liabilityinterests in VNR at $19.00 per unit for net proceeds of $92.8 million afterdeducting underwriting discounts and fees of $7.0 million. The proceeds wereused to reduce indebtedness under our reserve-based credit facility by $80.0million and the balance was used for the payment of accrued distributions topre-IPO unitholders and the payment of a deferred swap obligation.

 

***Permian Basin Acquisition***

 

On December 21,2007, we entered in to a Purchase and Sale Agreement with the ApacheCorporation for the purchase of certain oil and natural gas properties locatedin ten separate fields in the Permian Basin of West Texas and Southeastern NewMexico. The purchase price for said assets was $78.3 million with an effectivedate of October 1, 2007. We completed this acquisition on January 31,2008 for an adjusted purchase price of $73.4 million, subject to customary postclosing adjustments. This acquisition was funded with borrowings under ourreserve-based credit facility. In this purchase, we acquired working interestsin 390 gross wells (67 net wells), 49 of which we operate. With respect tooperations, we have established two district offices, one in Lovington, NewMexico and the other in Christoval, Texas to manage these assets. Our operatingfocus will be on maximizing existing production and looking for complementaryacquisitions that we can add to this operating platform. With this acquisition,based on internal reserve estimates we acquired 4.4 million barrels of oilequivalent, 83% of which is oil and 90% of which is proved developed producing.The current net production attributable to this purchase is approximately 800barrels of oil equivalent per day and the reserves-to-production ratio is 15years. With the closing of this acquisition, our daily production and totalreserves increased approximately 40%. The effects of this acquisition are notreflected in the reserves, cash flows and other financial and operatinginformation described below as of December 31, 2007 due to the acquisitionclosing on January 31, 2008.

 

39

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***Our Relationship with Vinland***

 

On April 18, 2007but effective as of January 5, 2007, we entered into various agreementswith Vinland, under which we rely on Vinland to operate our existing producingwells in Appalachia and coordinate our development drilling program inAppalachia. We expect to benefit from the substantial development andoperational expertise of Vinland management in the Appalachian Basin. Under amanagement services agreement, Vinland advises and consults with us regardingall aspects of our production and development operations in Appalachia and providesus with administrative support services as necessary for the operation of ourbusiness. In addition, Vinland may, but does not have any obligation to,provide us with acquisition services under the management services agreement.While Vinland is not obligated to provide us with acquisition services, weexpect that due to significant common ownership Vinland has an incentive togrow our business by helping us to identify, evaluate and complete acquisitionsthat will be accretive to our distributable cash. In addition, under agathering and compression agreement that we entered into with Vinland EnergyGathering, LLC (“VEG”), VEG gathers, compresses, delivers and provides theservices necessary for us to market our natural gas production in the area ofmutual interest, or AMI. VEG will deliver our natural gas production to certaindesignated interconnects with third-party transporters. Since the variousagreements were executed on April 18, 2007 but were effective as of January 5,2007, Vinland reimbursed us for the drilling costs and expenses that weincurred on their behalf associated with their interest in the wells drilledbetween January 5, 2007 and April 18, 2007. In addition, Vinlandreimbursed us for selling, general and administrative expenses that we incurredon their behalf between January 5, 2007 and April 18, 2007. Wereimbursed Vinland for certain transaction costs and expenses relating toentering into these agreements.

 

***Restructuring Plan***

 

Prior to the separation,our Predecessor owned all of the assets in Appalachia that are currently ownedby us and Vinland. As part of the separation of our operating company andVinland, effective January 5, 2007, we conveyed to Vinland 60% of ourPredecessor’s working interest in the known producing horizons in approximately95,000 gross undeveloped acres in the AMI, 100% of our Predecessor’s interestin an additional 125,000 undeveloped acres and certain coalbed methane rightslocated in the Appalachian Basin, the rights to any natural gas and oil locatedon our acreage at depths above and 100 feet below our known producing horizons,all of our gathering and compression assets and all employees other than ourPresident and Chief Executive Officer and our Executive Vice President andChief Financial Officer. We retained all of our Predecessor’s proved producingwells and associated reserves. We also retained 40% of our Predecessor’sworking interest in the known producing horizons in approximately 95,000 grossundeveloped acres in the AMI and a contract right to receive approximately 99%of the net proceeds, after deducting royalties paid to other parties, severancetaxes, third-party transportation costs, costs incurred in the operation ofwells and overhead costs, from the sale of production from certain producingnatural gas and oil wells, which accounted for approximately 4.5% of ourestimated proved reserves as of December 31, 2007. In addition, we changedthe name of our operating company from Nami Holding Company, LLC to VanguardNatural Gas, LLC. Collectively, we refer to these events as the “Restructuring.”

 

***Private Offering***

 

In April 2007, wecompleted a private equity offering pursuant to which we issued 2,290,000** **units to certain private investors,which we collectively refer to as the Private Investors, for $41.2 million. Weused the net proceeds of this private equity offering to make a distribution toMajeed S. Nami, our sole unitholder at the time, who used a portion of thesefunds to capitalize Vinland and also paid us $3.9 million to reduce outstandingaccounts receivable from Vinland. We then used the $3.9 million to repayborrowings and interest under our reserve-based credit facility, and forgeneral limited liability company purposes. Under the terms of the privateoffering, all outstanding units accrued distributions at $1.75 annually fromthe closing of the private offering to September 30, 2007 and thendistributions payable to the Private Investors only increased to $2.40 untilthe completion of the IPO at which time all accrued distributions totaling $5.6million were paid.

 

40

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***Reserve-Based Credit Facility***

 

On January 3, 2007,our operating company entered into a reserve-based credit facility. Our initialborrowing base under the reserve-based credit facility was set at $115.5million. However, the borrowing base was subject to $1.0 million reductions permonth starting on July 1, 2007 through November 1, 2007, whichresulted in a borrowing base of $110.5 million as reaffirmed in November 2007pursuant to a semi-annual borrowing base redetermination. We applied $80.0million of our net proceeds from our IPO in October 2007 to reduce ourindebtedness under our reserve-based credit facility and as of December 31,2007, our borrowings under the reserve-based credit facility totaled$37.4 million. The reserve-based credit facility is available for ourgeneral limited liability company purposes, including, without limitation,capital expenditures and acquisitions. Our obligations under the reserve-basedcredit facility are secured by substantially all of our assets.

 

During 2007, there weresix amendments to the reserve-based credit facility, the sixth of which wasexecuted in November 2007.  Thisamendment set our borrowing base under our reserve-based credit facility at$110.5 million pursuant to our semi-annual redetermination, revised thecovenant governing borrowing funds to make distributions, and lowered ourborrowing rates. The covenant which prohibited us from making distributions ifour borrowings exceeded 80% of our borrowing base was revised to allow us tomake distributions if our borrowings were less than 90% of our borrowing base.In addition, the applicable margins on our borrowing base utilization grid werelowered to reflect the following:

 

**Borrowing Base Utilization Grid**

 
| **Borrowing Base Utilization Percentage** | ** ** | **<****25%** | ** ** | **>25% <50%** | ** ** | **>50% <75%** | ** ** | **>75%** | ** ** |
|----------------------------------------------------------|------------|-----------------|------------|--------------------------|------------|--------------------------|------------|-------------|------------|
| Eurodollar Loans                                         |       | 1.000           | %          | 1.250                    | %          | 1.500                    | %          | 1.750       | %          |
| ABR Loans                                                |       | 0.000           | %          | 0.250                    | %          | 0.500                    | %          | 0.750       | %          |
| Commitment Fee  Rate                                     |       | 0.250           | %          | 0.300                    | %          | 0.375                    | %          | 0.375       | %          |
| Letter of Credit  Fee                                    |       | 1.000           | %          | 1.250                    | %          | 1.500                    | %          | 1.750       | %          |

 

Our reserve-based creditfacility was amended and restated in February, 2008 to extend the maturity datefrom January 3, 2011 to March 31, 2011, increase the facility amountfrom $200.0 million to $400.0 million, increase our borrowing base from $110.5million to $150.0 million and add two financial institutions.

 

**Outlook**

 

Our revenue, cash flowfrom operations and future growth depend substantially on factors beyond ourcontrol, such as economic, political and regulatory developments, competitionfrom other sources of energy, and access to capital. Natural gas and oil priceshistorically have been volatile and may fluctuate widely in the future.Sustained periods of low prices for natural gas or oil could materially andadversely affect our financial position, our results of operations, thequantities of natural gas and oil reserves that we can economically produce andour access to capital. As required by our reserve-based credit facility, wehave mitigated this volatility for the years 2007 through 2011 by implementinga hedging program on our proved producing and total anticipated productionduring this time frame.

 

We face the challenge ofnatural gas production declines. As a given well’s initial reservoir pressuresare depleted, natural gas production decreases, thus reducing our total naturalgas reserves. We attempt to overcome this natural decline both by drilling onour properties and acquiring additional reserves. We will maintain our focus oncontrolling costs to add reserves through drilling and acquisitions, as well ascontrolling the corresponding costs necessary to produce such reserves. Ourability to add reserves through drilling is dependent on our capital resourcesand can be limited by many factors, including the ability of Vinland to timelyobtain drilling permits and regulatory approvals. Any delays in drilling,completion or connection to gathering lines of our new wells will negativelyimpact the rate of our production, which may have an adverse effect on ourrevenues and as a result, cash available for distribution. In accordance withour business plan, we intend to invest the capital necessary to maintain ourproduction at existing levels over the long-term.

 

41

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**Comparability of Financial Statements**

 

The historical financialstatements of our Predecessor included in this Annual Report on Form 10-Kmay not be comparable to our results of operations for the following reasons:

 
| · |   | We conveyed to Vinland  60% of our Predecessor’s working interest in the known producing horizons in  approximately 95,000 gross undeveloped acres in the AMI, 100% of our  Predecessor’s interest in an additional 125,000 undeveloped acres and certain  coalbed methane rights located in the Appalachian Basin, the rights to any  natural gas and oil located on our acreage at depths above and 100 feet below  our known producing horizons and all of our gathering and compression assets.  In addition, all of the employees except our President and Chief Executive  Officer and Executive Vice-President and Chief Financial Officer were  transferred to Vinland. |
|--------|--------|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|   |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      |
| · |   | We entered into a  management services agreement and a gathering and compression agreement with  Vinland which will fix a portion of our production costs for wells owned in  the AMI.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    |
|   |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      |
| · |   | Our Predecessor did not  account for its derivative instruments as cash flow hedges under SFAS  No. 133 until the first quarter of 2007. Accordingly, the changes in the  fair value of its derivative instruments were reflected in earnings for all  periods prior to 2007 and in other comprehensive income (loss) for the year  ended December 31, 2007.                                                                                                                                                                                                                                                                                                                    |
|   |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      |
| · |   | We will incur  additional selling, general and administrative expense estimated to be $1.9  million per year for costs associated with being a public company. Also, we  will incur non-cash compensation charges for the 420,000 Class B units  granted to management, the 40,000 Class B units to be issued in the  future, 175,000 options granted to management under our Long-Term Incentive  Plan and phantom units granted to management in 2008.                                                                                                                                                                                                                        |

 

**Results of Operations**

 

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

 
| ** **                                    | ** ** | **Year Ended December 31,** | ** ** |
|-----------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                    | ** ** | **Vanguard**                               | ** ** | **Vanguard  Predecessor** | ** ** |
| ** **                                    | ** ** | **2007**                                   | ** ** | **2006** | ** ** | **2005** | ** ** |
| ** **                                    | ** ** | ** **                                 | ** ** | **(in thousands)** | ** ** |
| **Revenues:**                                 |       |                                       |       |   |   |   |   |
| Natural gas and  oil sales                    |       | $                                          | 34,541     |   | $ | 38,184 |   | $ | 40,299 |   |
| Realized losses  on derivative contracts      |       | (702                                       | )          | (2,208 | ) | (10,024 | ) |
| Change in fair  value of derivative contracts |       | —                                     |       | 17,748 |   | (18,779 | ) |
| Other                                         |       | —                                     |       | 665 |   | 451 |   |
| **Total  revenues**                           |       | $                                          | 33,839     |   | $ | 54,389 |   | $ | 11,947 |   |
| **Costs  and expenses:**                      |       |                                       |       |   |   |   |   |
| Lease operating  expenses                     |       | $                                          | 5,066      |   | $ | 4,896 |   | $ | 4,607 |   |
| Depreciation,  depletion and amortization     |       | 8,981                                      |       | 8,633 |   | 6,189 |   |
| Selling, general  and administrative expenses |       | 3,507                                      |       | 5,199 |   | 5,946 |   |
| Bad debt expense                              |       | 1,007                                      |       | — |   | — |   |
| Taxes other than  income                      |       | 2,054                                      |       | 1,774 |   | 1,249 |   |
| **Total  costs and expenses**                 |       | $                                          | 20,615     |   | $ | 20,502 |   | $ | 17,991 |   |
| **Other  expenses:**                          |       |                                       |       |   |   |   |   |
| Interest  expense, net                        |       | $                                          | (8,073     | ) | $ | (7,332 | ) | $ | (4,514 | ) |
| Loss on  extinguishment of debt               |       | (2,502                                     | )          | — |   | — |   |

 

42

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

 

***Revenues***

 

Natural gas and oil salesdecreased to approximately $34.5 million for the year ended December 31,2007 from approximately $38.1 million for the year ended December 31,2006. The key revenue measurements were as follows:

 
| ** **                              | ** ** | **Year Ended  December 31,** | ** ** | ** **                | ** ** |
|-----------------------------------------|------------|----------------------------------------|------------|---------------------------|------------|
| ** **                              | ** ** | **Vanguard**                           | ** ** | **Vanguard  Predecessor** | ** ** | **Percentage  Increase** | ** ** |
| ** **                              | ** ** | **2007**                               | ** ** | **2006**                  | ** ** | **(Decrease)** | ** ** |
| **Net  Production:**                    |       |                                   |       |                      |       |   |   |
| Total Production  (MMcfe)               |       | 4,238                                  |       | 4,378                     |       | (3 | )% |
| Average Daily  production (Mcfe/d)      |       | 11,610                                 |       | 11,995                    |       | (3 | )% |
| **Average  Sales Price per Mcfe:**      |       |                                   |       |                      |       |   |   |
| Average sales  price (including hedges) |       | $                                      | 8.99       | (a)                       | $          | 8.22 |   | 9 | % |
| Average sales  price (excluding hedges) |       | $                                      | 8.15       |                      | $          | 8.72 |   | (7 | )% |

 

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(a) Excludespremiums paid on settled derivatives.

 

The decrease in naturalgas and oil sales was primarily due to the 3% decrease in production coupledwith a 7% decrease in the average realized sales price received (excludinghedges) during the year ended December 31, 2007 over December 31,2006. The decrease in production can be attributed to our drilling 83 wellsduring the 2007 as compared to the Predecessor drilling 100 wells in the sameperiod in 2006.

 

***Hedging Activities***

 

During the year ended December 31,2007, we hedged approximately 88% of our natural gas production, which resultedin reported revenues that were approximately $0.7 million lower than we wouldhave achieved at unhedged prices. However, the actual cash impact of the hedgesincreased realizations by $4.3 million for the period after excluding thepremiums paid on the settled derivatives. In addition, in January 2007, weterminated existing natural gas swaps at a cost of approximately $2.8 millionwhich resulted in an additional realized loss on derivative contracts ofapproximately $0.8 million during the year ended December 31, 2007. Duringthe year ended December 31, 2006, our Predecessor hedged approximately 53%of our natural gas production, which resulted in revenues that wereapproximately $2.2 million lower than our Predecessor would have achieved atunhedged prices. The derivative contracts entered into in 2006 were notspecifically designated as hedges under SFAS No. 133,*  Accountingfor Derivative Instruments and Hedging Activities*  and therefore did not qualify for hedgeaccounting treatment. As a result, the change in the fair value of thesenatural gas derivative contracts was marked to market in earnings each periodin 2006 and resulted in a $17.7 million non-cash gain for the year ended December 31,2006.

 

***Costs and Expenses***

 

Production costs consistof the lease operating expenses and taxes other than income taxes (severanceand ad valorem taxes). Lease operating expenses includes third-partytransportation costs, operating and maintenance costs associated with ourgathering systems (which were conveyed to Vinland in connection with theRestructuring) and other customary charges. As a result of the Restructuring,lease operating expenses for the year ended December 31, 2007 includesthird-party transportation costs, a $60 per month per well administrativecharge pursuant to a management services agreement with Vinland, a $0.25 perMcf and $0.55 per Mcf gathering and compression charge for production fromwells drilled pre and post January 5, 2007, respectively, paid to Vinlandpursuant to a gathering and compression agreement with Vinland, as well asother customary charges.

 

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Lease operating expensesincreased only slightly to $5.1 million for the year ended December 31,2007 as compared to $4.9 million for the year ended December 31, 2006 dueprimarily to amounts paid to Vinland under the management services agreementand gathering and compression agreement being comparable to our actual costsincurred for the same period in 2006. On a per Mcfe basis, lease operatingexpenses increased by 7% to $1.20 for the year ended December 31, 2007compared to $1.12 for the same period in 2006. Severance taxes are a functionof volumes and revenues generated from production. Ad valorem taxes vary bystate and county and are based on the value of our reserves. Taxes other thanincome increased $0.3 million to $2.1 million or 20% on a per Mcfe basis, forthe year ended December 31, 2007 as compared to the year ended December 31,2006. This increase was principally due to a $0.2 million underaccrual ofseverance taxes in 2006, which was charged to expense in the first quarter of2007.

 
| ** **                         | ** ** | **Year Ended  December 31,** | ** ** | ** **                | ** ** |
|------------------------------------|------------|----------------------------------------|------------|---------------------------|------------|
| ** **                         | ** ** | **Vanguard**                           | ** ** | **Vanguard  Predecessor** | ** ** | **Percentage** | ** ** |
| ** **                         | ** ** | **2007**                               | ** ** | **2006**                  | ** ** | **Increase** | ** ** |
| Lease operating  expenses per Mcfe |       | $                                      | 1.20       |                      | $          | 1.12 |   | 7 | % |
| Production taxes  per Mcfe         |       | $                                      | 0.48       |                      | $          | 0.40 |   | 20 | % |

 

Depreciation, depletionand amortization increased $0.3 million to $8.9 million for the year ended December 31,2007 despite the conveyance of certain assets to Vinland pursuant to theRestructuring effective January 2007. This result occurred due to theconveyance of long-lived depreciable assets which generated little associateddepreciation and the conveyed value of the 60% interest in proved undevelopedproperties which was largely offset by the cost of new wells drilled since December 31,2006. In addition, the increase in depletion can be attributed to upwardrevisions of future drilling costs in the 2007 reserve report which increasedthe full cost pool to be depleted.

 

Selling, general andadministrative expenses include the cost of our employees and executiveofficers, related benefits, office leases, professional fees and other costsassociated with being a public company not directly resulting from fieldoperations. These expenses for the year ended December 31, 2007 decreased$1.7 million to $3.5 million as compared to $5.2 million for the year ended December 31,2006 primarily due to the impact of the Restructuring which transferred all ofthe employees other than two of its officers to Vinland. The decrease inselling, general and administrative expenses during the year ended December 31,2007 as compared to 2006 was offset by two principal factors. First, ourPredecessor capitalized $3.9 million of internal costs under the full costmethod of accounting for natural gas and oil properties for the year ended December 31,2006 whereas we have not capitalized any internal costs in 2007, respectively.Second, the year ended December 31, 2007 includes a $2.1 million non-cashcompensation charge related to the grant of Class B units to management,an employee and a board member in April, August and October 2007.Excluding the impact of the approximate $2.1 million non-cash compensationcharge discussed above, selling, general and administrative expenses would havebeen $1.4 million for the year ended December 31, 2007 or 73% lower thanthe comparable 2006 period.

 

Bad debt expense ofapproximately $1.0 million was recorded during the year ended December 31,2007 as a result of a provision for a loss on the entire amount due from acustomer which filed for protection under Chapter 11 of the Bankruptcy Code in May 2007.The account receivable was due from oil sales through December 2006 atwhich time we ceased selling oil to the customer. As the amount of anypotential recovery is uncertain, we elected to reserve the entire balance. Webegan selling our oil production to a new customer beginning March 2007.

 

Interest and financingexpenses were approximately $8.1 million for the year ended December 31,2007 compared to approximately $7.3 million for the year ended December 31,2006. The increase in 2007 is primarily due to increased debt levels associatedwith drilling additional wells and rising interest rates. In addition, ourinterest rates during 2007 were directly affected by the provision in ourcredit facility which increased our rates by 1% on LIBOR loans effective July 1,2007 until we completed our IPO in October 2007.

 

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**Year Ended December 31, 2006 Compared to Year Ended December 31,2005 (Predecessor)**

 

***Revenues***

 

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

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

 

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

 

***Hedging Activities***

 

During the year ended December 31,2006, our Predecessor hedged approximately 53% of our natural gas production,which resulted in revenues that were $2.2 million less than we would haveachieved at unhedged prices. During the year ended December 31, 2005, ourPredecessor hedged approximately 68% of our natural gas production, whichresulted in revenues that were $10.0 million less than our Predecessor wouldhave achieved at unhedged prices. The derivative contracts entered into in 2006and 2005 were not specifically designated as hedges under SFAS No. 133,*Accounting for Derivative Instruments and HedgingActivities* and therefore did not qualify for hedge accountingtreatment. As a result, the change in the fair value of these natural gasderivative contracts were marked to market in our Predecessor’s earnings eachperiod and resulted in $17.7 million in non-cash gain and $18.8 million innon-cash loss in 2006 and 2005, respectively.

 

***Costs and Expenses***

 

Production costs consistof lease operating expenses and production taxes (severance and ad valoremtaxes). Lease operating expenses includes gathering and compression fees,operating and maintenance costs associated with our Predecessor’s gatheringsystems (which were conveyed to Vinland in connection with the Restructuring)and other customary charges. Production taxes are a function of volumes andrevenues generated from production. Ad valorem taxes vary by state and countyand are based on the value of our reserves. Lease operating expenses increased$0.3 million to $4.9 million for the year ended December 31, 2006 ascompared to the year ended December 31, 2005 due to the 100 additionalwells drilled in 2006. On a per Mcfe basis, lease operating expenses declined5% to $1.12 in 2006 as compared to $1.18 in 2005 due to increased production in2006. Production taxes increased $0.5 million to $1.8 million or 25% on a perMcfe basis for the year ended December 31, 2006 as compared to the yearended December 31, 2005 principally due to a significant increase in advalorem taxes.

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

 

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

 

Selling, general andadministrative expenses include the costs of our Predecessor’s employees andexecutive officers, related benefits, office leases, professional fees andother costs not directly associated with field operations. Selling, general andadministrative expenses decreased $0.7 million during the year ended December 31,2006 as compared to the year ended December 31, 2005. This represents a13% decrease for the year ended December 31, 2006 over 2005 resulting froma $2.8 million increase in the amount of capitalized internal costs incurred inconnection with the development of natural gas and oil reserves offset by aone-time non-recurring $1.2 million litigation settlement and related legalcosts.

 

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

 

**Critical Accounting Policies and Estimates**

 

The discussion andanalysis of our financial condition and results of operations are based uponthe consolidated financial statements, which have been prepared in accordancewith accounting principles generally accepted in the United States. Thepreparation of these financial statements requires us to make estimates andassumptions that affect the reported amounts of assets, liabilities, revenuesand expenses, and related disclosure of contingent assets and liabilities.Certain accounting policies involve judgments and uncertainties to such anextent that there is reasonable likelihood that materially different amountscould have been reported under different conditions, or if different assumptionshad been used. We evaluate our estimates and assumptions on a regular basis. Webase our estimates on historical experience and various other assumptions thatare believed to be reasonable under the circumstances, the results of whichform the basis for making judgments about the carrying values of assets andliabilities that are not readily apparent from other sources. Actual resultsmay differ from these estimates and assumptions used in preparation of ourfinancial statements. Below, we have provided expanded discussion of our moresignificant accounting policies, estimates and judgments. We have discussed thedevelopment, selection and disclosure of each of these with our auditcommittee. We believe these accounting policies reflect our more significantestimates and assumptions used in preparation of our financial statements.Please read *Note 1* to the Notes to the ConsolidatedFinancial Statements included in item 8 of this Annual Report on Form 10-Kfor a discussion of additional accounting policies and estimates made bymanagement.

 

**Full-Cost Method of Accounting for Natural Gas and OilProperties**

 

The accounting for ourbusiness is subject to special accounting rules that are unique to thenatural gas and oil industry. There are two allowable methods of accounting forgas and oil business activities: the successful-efforts method and thefull-cost method. There are several significant differences between thesemethods. Under the successful-efforts method, costs such as geological andgeophysical (G&G), exploratory dry holes and delay rentals are expensed asincurred, where under the full-cost method these types of charges would becapitalized to the full-cost pool. In the measurement of impairment of gas andoil properties, the successful-efforts method of accounting follows theguidance provided in Statement of Financial Accounting Standards (SFAS) No. 144,“Accounting for the Impairment or Disposal of Long-Lived Assets,” where thefirst measurement for impairment is to compare the net book value of therelated asset to its undiscounted future cash flows using commodity pricesconsistent with management expectations. Under the full-cost method, the netbook value (full-cost pool) is compared to the future net cash flows discountedat 10 percent using commodity prices in effect on the last day of the reportingperiod (ceiling limitation). If the full-cost pool is in excess of the ceilinglimitation, the excess amount is charged through income.

 

We have elected to usethe full-cost method to account for our investment in natural gas and oilproperties. Under this method, we capitalize all acquisition, exploration anddevelopment costs for the purpose of finding natural gas and oil reserves,including salaries, benefits and other internal costs directly related to thesefinding activities. For the year ended December 31, 2007, there were nointernal costs capitalized. For the years 2005 and 2006 such internal costscapitalized totaled $1.1 million and $3.9 million, respectively. Although someof these costs will ultimately result in no additional reserves, we expect thebenefits of successful wells to more than offset the costs of any unsuccessfulones. In addition, gains or losses on the sale or other disposition of naturalgas and oil 

 

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properties are notrecognized unless the gain or loss would significantly alter the relationshipbetween capitalized costs and proved reserves. Our results of operations wouldhave been different had we used the successful-efforts method for our naturalgas and oil investments. Generally, the application of the full-cost method ofaccounting results in higher capitalized costs and higher depletion ratescompared to similar companies applying the successful-efforts method of accounting.

 

**Full-Cost Ceiling Test**

 

Atthe end of each quarterly reporting period, the unamortized cost of natural gasand oil properties, after deducting the asset retirement obligation is limitedto the sum of the estimated future net revenues from proved properties usingperiod-end prices, after giving effect to cash flow hedge positions, discountedat 10% and the lower of cost or fair value of unproved properties (“CeilingTest”).

 

The calculation of theCeiling Test and the provision for depletion and amortization are based onestimates of proved reserves. There are numerous uncertainties inherent inestimating quantities of proved reserves and in projecting the future rates ofproduction, timing, and plan of development as more fully discussed in “—NaturalGas and Oil Reserve Quantities” below. Due to the imprecision in estimatingnatural gas and oil reserves as well as the potential volatility in natural gasand oil prices and their effect on the carrying value of our proved natural gasand oil reserves, there can be no assurance that Ceiling Test write-downs inthe future will not be required as a result of factors that may negativelyaffect the present value of proved natural gas and oil properties. Thesefactors include declining natural gas and oil prices, downward revisions inestimated proved natural gas and oil reserve quantities and unsuccessfuldrilling activities.

 

At December 31,2007, we had a cushion (i.e. the excess of the ceiling over our capitalizedcosts) of $34.0 million. At December 31, 2006, our Predecessor had acushion of $42.1 million.

 

**AssetRetirement Obligation**

 

We have obligations toremove tangible equipment and restore land at the end of a natural gas or oilwells life. Our removal and restoration obligations are primarily associatedwith plugging and abandoning wells. Estimating the future plugging andabandonment costs requires management to make estimates and judgments inherentin the present value calculation of the future obligation. These includeultimate plugging and abandonment costs, inflation factors, credit adjusteddiscount rates, and timing of the obligation. To the extent future revisions tothese assumptions impact the present value of the existing asset retirementobligation liability, a corresponding adjustment is made to the natural gas andoil property balance.

 

**Natural Gas and Oil Reserve Quantities**

 

Our estimate of provedreserves is based on the quantities of natural gas and oil that engineering andgeological analyses demonstrate, with reasonable certainty, to be recoverablefrom established reservoirs in the future under current operating and economicparameters. NSAI prepares a reserve and economic evaluation of all ourproperties on a well-by-well basis.

 

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

 

Our proved reserveestimates are a function of many assumptions, all of which could deviatesignificantly from actual results. As such, reserve estimates may materiallyvary from the ultimate quantities of natural gas, natural gas liquids and oileventually recovered.

 

**Revenue Recognition**

 

Sales of natural gas andoil are recognized when natural gas has been delivered to a custody transferpoint, persuasive evidence of a sales arrangement exists, the rights andresponsibility of ownership pass to the purchaser upon delivery, collection ofrevenue from the sale is reasonably assured, and the sales price is fixed ordeterminable. 

 

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We sell natural gas on amonthly basis. Virtually all of our contracts’ pricing provisions are tied to amarket index, with certain adjustments based on, among other factors, whether awell delivers to a gathering or transmission line, quality of natural gas, andprevailing supply and demand conditions, so that the price of the natural gasfluctuates to remain competitive with other available natural gas supplies. Asa result, our revenues from the sale of natural gas will suffer if marketprices decline and benefit if they increase without consideration of hedging.We believe that the pricing provisions of our natural gas contracts arecustomary in the industry.

 

Gas imbalances occur whenwe sell more or less than our entitled ownership percentage of total gasproduction. Any amount received in excess of our share is treated as aliability. If we receive less than our entitled share the underproduction isrecorded as a receivable. We did not have any significant gas imbalancepositions at December 31, 2007 or 2006.

 

**Price Risk Management Activities**

 

We periodically usederivative financial instruments to achieve a more predictable cash flow fromour natural gas and oil production by reducing our exposure to pricefluctuations. Currently, these derivative financial instruments includefixed-price swaps, collars and put options. We account for these activitiespursuant to SFAS No. 133—*Accounting forDerivative Instruments and Hedging Activities*, as amended. Thisstatement establishes accounting and reporting standards requiring thatderivative instruments (including certain derivative instruments embedded inother contracts) be recorded at fair market value and included in the balancesheet as assets or liabilities.

 

The accounting forchanges in the fair market value of a derivative instrument depends on theintended use of the derivative instrument and the resulting designation, whichis established at the inception of a derivative instrument. SFAS No. 133requires that a company formally document, at the inception of a hedge, thehedging relationship and the company’s risk management objective and strategyfor undertaking the hedge, including identification of the hedging instrument,the hedged item or transaction, the nature of the risk being hedged, the methodthat will be used to assess effectiveness and the method that will be used tomeasure hedge ineffectiveness of derivative instruments that receive hedgeaccounting treatment.

 

Our Predecessor did notspecifically designate the derivative instruments established in 2005 and 2006as hedges under SFAS No. 133, even though they protected our Predecessorfrom changes in commodity prices. Therefore, the mark to market of theseinstruments was recorded in current earnings. Further, these mark to marketamounts represent non-cash charges. The derivative instruments we establishedin 2007 as well as future derivative instruments will be designated as hedgesunder SFAS No. 133. Had no hedges been in place, we would have receivedadditional revenue of $0.7 million during 2007 and our Predecessor would havereceived additional revenue of $10.0 million and $2.2 million during 2005 and2006, respectively. In January 2007, we terminated existing hedges at acost of approximately $2.8 million, of which $0.8 million is reflected as arealized loss from derivative contracts on the statement of operations for theyear ended December 31, 2007.

 

For derivativeinstruments designated as cash flow hedges, changes in fair market value, tothe extent the hedge is effective, are recognized in other comprehensive income(loss) until the hedged item is settled and recognized in earnings. Hedgeeffectiveness is assessed at least quarterly based on total changes in thederivative instrument’s fair market value. Any ineffective portion of thederivative instrument’s change in fair market value is recognized immediatelyin earnings.

 

**Stock Based Compensation**

 

We account for StockBased Compensation pursuant to SFAS No. 123(R)—*Share-Based Payment*. SFAS No. 123(R) requires anentity to recognize the grant-date fair-value of stock options and otherequity-based compensation issued to employees in the income statement and eliminatesthe alternative to use the intrinsic value method of accounting that wasprovided in SFAS No. 123, which generally resulted in no compensationexpense recorded in the financial statements related to the issuance of equityawards to employees. It establishes fair value as the measurement objective inaccounting for share-based payment arrangements and requires all companies toapply a fair-value-based measurement method in accounting for generally allshare-based payment transactions with employees. On March 29, 2005, theSEC staff issued SAB No. 107, Share-Based Payment, to express the views ofthe staff regarding the interaction between SFAS No. 123(R) andcertain SEC rules and regulations and to provide the staff’s viewsregarding the valuation of share-based payment arrangements for publiccompanies.

 

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In April 2007,certain members of management were granted 365,000 restricted Class Bunits which vest over two years. In addition, another 55,000 restricted Class Bunits were issued to two new employees in August 2007, which will vestover three years. In October 2007, a board member was granted 5,000 commonunits which vest over one year. There are an additional 40,000 Class Bunits available to be issued in the future. These units were granted as partialconsideration for services to be performed under employment contracts and thuswill be subject to accounting for these grants under SFAS No. 123(R)—*Share-Based Payment*.

 

With respect to the420,000 restricted Class B units granted, we expect to incur$3.2 million, $2.2 million and $0.2 million in non-cash compensationexpense for the years ended 2008, 2009 and 2010, respectively. For the yearended December 31, 2007, we recorded $2.1 million of non-cashcompensation expense. Non-cash compensation expense to be incurred on the40,000 Class B units to be issued in the future will be determinedbased on the trading price of the units when they are granted.

 

**NewAccounting Pronouncements Issued But Not Yet Adopted**

 

In September 2006,the Financial Accounting Standards Board (FASB) issued Statement of FinancialAccounting Standards No. 157 “Fair *Value Measurements*”(SFAS 157). SFAS 157 introduces a framework for measuring fair value andexpands required disclosure about fair value measurements of assets andliabilities. On February 6, 2008, the FASB issued a final FASB StaffPosition (FSP) No. FAS 157-b, “*Effective Date of FASBStatement No. 157*”. This FSP delays the effective date of FASBStatement No. 157, *Fair ValueMeasurements,*for all non-financial assets and non-financialliabilities, except those that are recognized or disclosed at fair value in thefinancial statements on a recurring basis. In addition, the FSP removes certainleasing transactions from the scope of SFAS 157. The effective date of SFAS 157for non-financial assets and liabilities has been delayed by one year to fiscalyears beginning after November 15, 2008 and interim periods within thosefiscal years. SFAS 157 for financial assets and liabilities is effective forfiscal years beginning after November 15, 2007, and the Company adoptedthe standard for those assets and liabilities as of January 1, 2008. Theprincipal impact to the Company will be to require the Company to expand itsdisclosure regarding its derivative instruments and to include credit risk as apart of the calculation of the fair value of derivatives. The adoption of thisstandard did not have a material impact on the consolidated financialstatements.

 

In February 2007,the FASB issued SFAS No. 159, “*The FairValue Option for Financial Assets and Financial Liabilities, including anamendment of FASB Statement No. 115* “ (“SFAS 159”), whichpermits companies to choose, at specified dates, to measure certain eligiblefinancial instruments at fair value. The objective of SFAS 159 is toreduce volatility in preparer reporting that may be caused as a result ofmeasuring related financial assets and liabilities differently and to expandthe use of fair value measurements. The provisions of SFAS 159 apply onlyto entities that elect to use the fair value option and to all entities withavailable-for-sale and trading securities. Additional disclosures are alsorequired for instruments for which the fair value option is elected. SFAS 159is effective for fiscal years beginning after November 15, 2007. Noretrospective application is allowed, except for companies that choose to adoptearly. At the effective date, companies may elect the fair value option foreligible items that exist at that date, and the effect of the firstremeasurement to fair value must be reported as a cumulative-effect adjustmentto the opening balance of retained earnings. Effective January 1, 2008,the Company adopted SFAS No.159 and the adoption did not have a materialimpact on its consolidated financial statements.

 

In December 2007,the FASB issued SFAS No. 141 (revised 2007), *“Business Combinations”*(“SFAS 141(R)”), which replaces FASBStatement No. 141. SFAS 141(R) establishes principles andrequirements for how an acquirer recognizes and measures in its financialstatements the identifiable assets acquired, the liabilities assumed, anynon-controlling interest in the acquiree and the goodwill acquired. TheStatement also establishes disclosure requirements that will enable users toevaluate the nature and financial effects of the business combination. SFAS 141(R) iseffective for acquisitions that occur in an entity’s fiscal year that beginsafter December 15, 2008, which will be our fiscal year 2009. The impact,if any, will depend on the nature and size of business combinations that weconsummate after the effective date.

 

In December 2007,the FASB issued SFAS No. 160, *“Non-controllingInterests in Consolidated Financial statements—an amendment of ARB No. 51”*(“SFAS 160”). SFAS 160 requires that accounting and reporting forminority interests will be recharacterized as non-controlling interests andclassified as a component of equity. SFAS 160 also establishes reportingrequirements that provide sufficient disclosures that clearly identify anddistinguish between the interests of the parent and the interests of thenon-controlling owners. 

 

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SFAS 160 applies to allentities that prepare consolidated financial statements, except not-for-profitorganizations, but will affect only those entities that have an outstandingnon-controlling interest in one or more subsidiaries or that deconsolidate asubsidiary. This statement is effective as of the beginning of an entity’sfirst fiscal year beginning after December 15, 2008, which will be ourfiscal year 2009. Based upon the December 31, 2007 balance sheet, thestatement would have no impact.

 

In March 2008, theFASB issued SFAS No. 161, “*Disclosuresabout Derivative Instruments and Hedging*  *Activities”(“* SFAS No. 161”). SFAS No. 161 is intended to improvefinancial reporting about derivative  instrumentsand hedging activities by requiring enhanced disclosures to enable investors tobetter understand  their effects on anentity’s financial position, financial performance, and cash flows. SFAS No. 161achieves  these improvements by requiringdisclosure of the fair values of derivative instruments and their gains and  losses in a tabular format. It also providesmore information about an entity’s liquidity by requiring disclosure  of derivative features that are creditrisk-related. Finally, it requires cross-referencing within footnotes to  enable financial statement users to locateimportant information about derivative instruments. SFAS No. 161  is effective for financial statements issuedfor fiscal years and interim periods beginning after November 15,  2008, with early application encouraged. Weare evaluating the impact of SFAS No. 161 on our consolidated financialstatements and do not expect the impact of implementation to be material.

 

**Capital Resources and Liquidity**

 

We have utilized privateequity, proceeds from bank borrowings, cash flow from operations and, with ourrecent IPO, the public equity markets for capital resources andliquidity. To date, the primary use of capital has been for theacquisition and development of natural gas and oil properties; however, as aresult of our IPO, we expect to distribute to unitholders a significant portionof our free cash flow. As we execute our business strategy, we willcontinually monitor the capital resources available to us to meet futurefinancial obligations, planned capital expenditures, acquisition capital anddistributions to our unitholders. Our future success in growing reserves,production and cash flow will be highly dependent on the capital resourcesavailable to us and our success in drilling for or acquiring additionalreserves. We expect to fund our maintenance capital expenditures anddistributions to unitholders with cash flow from operations, while funding anyacquisition capital expenditures that we might incur with borrowings under ourreserve-based credit facility and a combination of private and public equitydepending on market conditions. As of March 14, 2008, we have $47.0million available to be borrowed under our reserve-based credit facility. Basedupon current expectations, we believe existing liquidity and capital resourceswill be sufficient for the conduct of our business and operations for theforeseeable future.

 

**Cash Flow from Operations**

 

Net cash provided byoperating activities was $1.4 million during the year ended December 31,2007, compared to $16.1 million during the year ended December 31,2006 and $10.5 million during the year ended December 31, 2005. Thedecrease in net cash provided by operating activities in 2007 was substantiallydue to the termination of existing natural gas swaps at a cost of approximately$2.8 million, cash paid on early extinguishment of debt of approximately $2.5million, the payment of $6.5 million for put option derivative contracts duringthe year ended December 31, 2007and the payment of $7.5 million ofpremiums to reset derivative strike prices at a higher value.

 

Our cash flow fromoperations is subject to many variables, the most significant of which is thevolatility of natural gas and oil prices. Natural gas and oil prices aredetermined primarily by prevailing market conditions, which are dependent onregional and worldwide economic and political activity, weather and otherfactors beyond our control. Our future cash flow from operations will depend onour ability to maintain and increase production through our drilling programand acquisitions, as well as the prices of natural gas and oil.

 

We enter into hedgingarrangements to reduce the impact of natural gas and oil price volatility onour cash flow from operations. Currently, we use a combination of fixed-priceswaps and NYMEX collars and put options to hedge natural gas and oil prices.  Please read “Item 1—Operations—HedgingActivities” for discussion of percentage of our expected production hedged.

 

By hedging a significantportion of our natural gas and oil production, we have mitigated, but noteliminated, the potential effects of changing prices on our cash flow fromoperations for those periods. While mitigating negative effects of fallingcommodity prices, these derivative contracts also limit the benefits we wouldreceive from increases in commodity prices. 

 

50

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It is our policy to enterinto derivative contracts only with counterparties that are major, creditworthyfinancial institutions deemed by management as competent and competitive marketmakers. The following table summarizes our hedges in place applicable toperiods subsequent to December 31, 2007. The fixed-price swap transactionsfor natural gas are settled based upon the Columbia Gas Appalachian Index (“TECOIndex”) and West Texas Intermediate light sweet for oil. The collars and putoptions for natural gas are settled based on the NYMEX price of natural gas atHenry Hub on the next to last trading day of the month. Settlement occurs onthe 25th dayfollowing the production month for the swaps and collars and on the 5th day of the production month for the putoptions.

 
| ** **                                                       | ** ** | **Natural Gas**                        | ** ** | **Oil**                             | ** ** |
|------------------------------------------------------------------|------------|---------------------------------------------|------------|-------------------------------------|------------|
| ** **                                                       | ** ** | **Fixed-Price  Swap Volumes  (MMBtu)** | ** ** | **Average  Swap  Price  ($/MMBtu)** | ** ** | **Put Option  Volumes  (MMBtu)** | ** ** | **Average  Price  ($/MMBtu)** | ** ** | **Collars  Volumes  (MMBtu)** | ** ** | **Floor – Ceiling  ($ /MMBtu)** | ** ** | **Fixed-Price  Swap  Volumes  (Bbls)** | ** ** | **Average  Swap  Price  ($ /Bbl)** | ** ** |
| Period from  January 1, 2008 through February 29, 2008 |       | 525,790                                     |       | $                                   | 9.00       |   | 305,474 |   | $ | 7.50 |   | — |   | $ | — |   | 17,500 |   | $ | 90.30 |   |
| Period from  March 1, 2008 through September 30, 2008  |       | 1,776,513                                   |       | $                                   | 9.00       |   | 1,358,972 |   | $ | 7.50 |   | 700,000 |   | $ | 7.50-9.00 |   | 117,000 |   | $ | 90.30 |   |
| Period from  October 1, 2008 through December 31, 2008 |       | 713,831                                     |       | $                                   | 9.00       |   | 546,920 |   | $ | 7.50 |   | 300,000 |   | $ | 7.50-9.25 |   | 48,000 |   | $ | 90.30 |   |
| Period from  January 1, 2009 through December 31, 2009 |       | 2,657,046                                   |       | $                                   | 8.85       |   | 1,840,139 |   | $ | 7.50 |   | 1,000,000 |   | $ | 7.50-9.00 |   | 181,500 |   | $ | 87.23 |   |
| Period from  January 1, 2010 through December 31, 2010 |       | 2,387,640                                   |       | $                                   | 8.76       |   | — |   | $ | — |   | 730,000 |   | $ | 8.00-9.30 |   | 164,250 |   | $ | 85.65 |   |
| Period from  January 1, 2011 through December 31, 2011 |       | 2,196,012                                   |       | $                                   | 7.15       |   | — |   | $ | — |   | — |   | $ | — |   | 151,250 |   | $ | 85.50 |   |
| Period from  January 1, 2012 through December 31, 2012 |       | —                                      |       | $                                   | —     |   | — |   | $ | — |   | — |   | $ | — |   | 144,000 |   | $ | 80.00 |   |

 

**Investing Activities—Acquisitions and Capital Expenditures**

 

Our capital expenditureswere $26.4 million in the year ended December 31, 2007 and $37.4 millionand $37.1 million for the years ended December 31, 2006 and 2005,respectively. The total for 2007 includes $12.8 million for drilling,development and exploitation of natural gas and oil properties, $3.6 millionfor acquisitions of natural gas and oil properties and $9.8 million fordeposits on acquisition of and prepayments of natural gas and oil properties.There were no acquisitions during 2006 or 2005. The totals for 2006 and 2005include $28.9 million and $34.4 for drilling, development and exploitation ofnatural gas properties, and $8.5 million and $2.7 million for furniture,fixtures and equipment, respectively, which includes expenditures forextensions of the gathering system and related midstream activities.

 

We currently anticipatethat our drilling budget for 2008 of between $17.6 million and $19.0 million,which predominantly consists of drilling and equipment is expected to be fundedthrough cash from operations. As of March 14, 2008, we had $47.0 millionavailable for borrowing under our reserve-based credit facility. Our currentborrowing base is $150.0 million. We anticipate that our cash flow fromoperations and available borrowing capacity under our reserve-based creditfacility will exceed our planned capital expenditures and other cashrequirements for the year ended December 31, 2008. However, future cashflows are subject to a number of variables, including the level of natural gasproduction and prices. There can be no assurance that operations and othercapital resources will provide cash in sufficient amounts to maintain plannedlevels of capital expenditures.

 

**Financing Activities**

 

***Reserve-Based Credit Facility***

 

On January 3, 2007,our operating company, Vanguard Natural Gas, LLC (formerly Nami HoldingCompany, LLC), entered into a reserve-based credit facility under which ourinitial borrowing base was set at $115.5 million. However, the borrowing basewas subject to $1.0 million reductions per month starting on July 1, 2007through November 1, 2007, which resulted in a borrowing base of $110.5million as reaffirmed in November 2007 pursuant to a semi-annual borrowingbase redetermination. 

 

51

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We applied $80.0 millionof our net proceeds from our IPO in October 2007 to reduce ourindebtedness under our reserve-based credit facility and as of December 31,2007, our borrowings under the reserve-based credit facility totaled$37.4 million. In January and February, 2008, we borrowed anadditional $65.6 million under our reserve-based credit facility principally tofund the acquisition of oil and natural gas properties in the Permian Basinfrom Apache Corporation which resulted in our outstanding indebtedness of $103 millionat March 10, 2008.

 

Our reserve-based creditfacility was amended and restated in February 2008 to extend the maturitydate from January 2011 to March 2011, increase the facility amountfrom $200.0 million to $400.0 million, increase our borrowing base from $110.5million to $150.0 million and add two financial institutions. The increasein the borrowing base was principally the result of inclusion of the reservesrelated to the Permian Basin acquisition. As a result, as of March 14,2008, we have $47.0 million available to be borrowed under our reserve-basedcredit facility.

 

Borrowings under thereserve-based credit facility are available for development, exploitation andacquisition of natural gas and oil properties, working capital and general limitedliability company purposes.

 

At our election, interestis determined by reference to:

 

·     the London interbank offered rate, or LIBOR, plus anapplicable margin between 1.0 % and 1.75% per annum; or

 

·     a domestic bank rate plus an applicable margin between0.0% and 0.75% per annum.

 

Interest is generallypayable quarterly for domestic bank rate loans and at the applicable maturitydate for LIBOR loans, but not less frequently than quarterly.

 

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

 

·     incur indebtedness;

 

·     grant certain liens;

 

·     make certain loans, acquisitions, capital expendituresand investments;

 

·     make distributions;

 

·     merge or consolidate; or

 

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

 

The reserve-based creditfacility also contains covenants that, among other things, require us tomaintain specified ratios or conditions as follows:

 

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

 

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

 

·     consolidated debt to consolidated net income plusinterest expense, income taxes, depreciation, depletion, amortization, changesin fair value of derivative instruments and other similar charges, minus allnon-cash income added to consolidated net income, and giving pro forma effectto any acquisitions or capital expenditures of not more than 4.0 to 1.0.

 

We have the ability toborrow under the reserve-based credit facility to pay distributions tounitholders as long as there has not been a default or event of default and ifthe amount of borrowings outstanding under our reserve-based credit facility isless than 90% of the borrowing base.

 

52

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

 

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

 

·  a representation or warrantyis proven to be incorrect when made;

 

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

 

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

 

·  bankruptcy or insolvencyevents involving us or our subsidiaries;

 

·  the entry of, and failure topay, one or more adverse judgments in excess of $1.0 million or one or morenon-monetary judgments that could reasonably be expected to have a materialadverse effect and for which enforcement proceedings are brought or that arenot stayed pending appeal;

 

·  specified events relating toour employee benefit plans that could reasonably be expected to result inliabilities in excess of $1 .0 million in any year; and

 

·  a change of control, whichincludes (1) an acquisition of ownership, directly or indirectly,beneficially or of record, by any person or group (within the meaning of theSecurities Exchange Act of 1934 and the rules of the SEC) of equity interestsrepresenting more than 25% of the aggregate ordinary voting power representedby our issued and outstanding equity interests other than by Nami, or (2) thereplacement of a majority of our directors by persons not approved by our boardof directors.

 

***Off-Balance Sheet Arrangements***

 

We have no guarantees oroff-balance-sheet debt to third parties, and we maintain no debt obligationsthat contain provisions requiring accelerated payment of the relatedobligations in the event of specified levels of declines in credit ratings.

 

**Contingencies**

 

The Company regularlyanalyzes current information and accrues for probable liabilities on thedisposition of certain matters, as necessary. Liabilities for losscontingencies arising from claims, assessments, litigation and other sourcesare recorded when it is probable that a liability has been incurred and theamount can be reasonably estimated. As of December 31, 2007, there were nomaterial loss contingencies.

 

***Contractual Obligations***

 

A summary of ourcontractual obligations as of December 31, 2007 is provided in thefollowing table.

 
| ** **               | ** ** | **Payments Due by Year  (in thousands)** | ** ** |
|--------------------------|------------|--------------------------------------------------------------|------------|
| ** **               | ** ** | **2008**                                                     | ** ** | **2009** | ** ** | **2010** | ** ** | **2011** | ** ** | **2012** | ** ** | **After  2012** | ** ** | **Total** | ** ** |
| Management  compensation |       | $                                                            | 600        |   | $ | 600 |   | $ | 100 |   | $ | — |   | $ | — |   | $ | — |   | $ | 1,300 |   |
| Long-term debt           |       | —                                                       |       | — |   | — |   | 37,400 |   | — |   | — |   | 37,400 |   |
| Operating leases         |       | 41                                                           |       | 41 |   | 10 |   | — |   | — |   | — |   | 92 |   |
| Total                    |       | $                                                            | 641        |   | $ | 641 |   | $ | 110 |   | $ | 37,400 |   | $ | — |   | $ | — |   | $ | 38,792 |   |

 

53

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** **
| **ITEM 7A. ** | **QUANTITATIVE  AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK** |
|-------------------------|-----------------------------------------------------------------|

 

The primary objective ofthe following information is to provide forward-looking quantitative andqualitative information about our potential exposure to market risks. The term “marketrisk” refers to the risk of loss arising from adverse changes in natural gasand oil prices and interest rates. The disclosures are not meant to be preciseindicators of expected future losses, but rather indicators of reasonablypossible losses. This forward-looking information provides indicators of how weview and manage our ongoing market risk exposures. All of our market risksensitive instruments were entered into for purposes other than speculativetrading.

 

***Commodity Price Risk***

 

Our major market riskexposure is in the pricing applicable to our natural gas and oil production.Realized pricing is primarily driven by the TECO Index for natural gas and WestTexas Intermediate light sweet for oil. Pricing for natural gas and oilproduction has been volatile and unpredictable for several years, and we expectthis volatility to continue in the future. The prices we receive for productiondepend on many factors outside our control.

 

We enter into hedgingarrangements with respect to a portion of our projected natural gas and oilproduction through various transactions that hedge the future prices received.These transactions may include price swaps whereby we will receive afixed-price for our production and pay a variable market price to the contractcounterparty. Additionally, we have put options for which we pay thecounterparty the fair value at the purchase date. At the settlement date wereceive the excess, if any, of the fixed floor over the floating rate. Thesehedging activities are intended to support our realized commodity prices attargeted levels and to manage our exposure to natural gas and oil pricefluctuations. We do not hold or issue derivative instruments for speculativetrading purposes.

 

At December 31,2007, the fair value of hedges that settle during the next twelve months was anasset of approximately $4.0 million, which we are owed by our counterparties. A10% increase in the index gas price above the December 31, 2007 price forthe next twelve months would result in an increase in the value of the hedgesof approximately $1.6 million; conversely, a 10% decrease in the index gasprice would result in a decrease of approximately $1.3 million.

 

The following tablesummarizes derivatives in place applicable to periods subsequent to December 31,2007:

 
| ** **                   | ** ** | **January 1, -February 29,  2008** | ** ** | **March 1, -September 30,  2008** | ** ** | **October 1, - December 31,  2008** | ** ** | **Year  2009** | ** ** | **Year  2010** | ** ** | **Year  2011** | ** ** | **Year  2012** | ** ** |
|------------------------------|------------|---------------------------------------------------|------------|--------------------------------------------------|------------|---------------------------------------------------------|------------|----------------|------------|----------------|------------|----------------|------------|----------------|------------|
| **Gas Positions:**      | ** ** | ** **                                        | ** ** | ** **                                       | ** ** | ** **                                              | ** ** | ** **     | ** ** | ** **     | ** ** | ** **     | ** ** | ** **     | ** ** |
| Fixed Price Swaps: | ** ** | ** **                                        | ** ** | ** **                                       | ** ** | ** **                                              | ** ** | ** **     | ** ** | ** **     | ** ** | ** **     | ** ** | ** **     | ** ** |
| Hedged  Volume (MMBtu)       |       | 525,790                                           |       | 1,776,513                                        |       | 713,831                                                 |       | 2,657,046      |       | 2,387,640      |       | 2,196,012      |       | —         |       |
| Fixed  Price ($/MMBtu)       |       | $                                                 | 9.00       |                                             | $          | 9.00                                                    |       | $              | 9.00       |           | $          | 8.85           |       | $              | 8.76       |   | $ | 7.15 |   | $ | — |   |
| Puts:                        |       |                                              |       |                                             |       |                                                    |       |           |       |           |       |           |       |           |       |
| Hedged  Volume (MMBtu)       |       | 305,474                                           |       | 1,358,972                                        |       | 546,920                                                 |       | 1,840,139      |       | —         |       | —         |       | —         |       |
| Floor  Price ($/MMBtu)       |       | $                                                 | 7.50       |                                             | $          | 7.50                                                    |       | $              | 7.50       |           | $          | 7.50           |       | $              | —     |   | $ | — |   | $ | — |   |
| Collars:                     |       |                                              |       |                                             |       |                                                    |       |           |       |           |       |           |       |           |       |
| Hedged  Volume (MMBtu)       |       | —                                            |       | 700,000                                          |       | 300,000                                                 |       | 1,000,000      |       | 730,000        |       | —         |       | —         |       |
| Floor  Price ($/MMBtu)       |       | $                                                 | —     |                                             | $          | 7.50                                                    |       | $              | 7.50       |           | $          | 7.50           |       | $              | 8.00       |   | $ | — |   | $ | — |   |
| Ceiling  Price ($/MMBtu)     |       | $                                                 | —     |                                             | $          | 9.00                                                    |       | $              | 9.25       |           | $          | 9.00           |       | $              | 9.30       |   | $ | — |   | $ | — |   |
| Total:                       |       |                                              |       |                                             |       |                                                    |       |           |       |           |       |           |       |           |       |
| Hedged  Volume (MMBtu)       |       | 831,264                                           |       | 3,135,485                                        |       | 1,260,751                                               |       | 4,497,185      |       | 3,117,640      |       | 2,196,012      |       | —         |       |
|                         |       |                                              |       |                                             |       |                                                    |       |           |       |           |       |           |       |           |       |
| **Oil Positions:**           |       |                                              |       |                                             |       |                                                    |       |           |       |           |       |           |       |           |       |
| Fixed  Price Swaps:          |       |                                              |       |                                             |       |                                                    |       |           |       |           |       |           |       |           |       |
| Hedged  Volume (Bbls)        |       | 17,500                                            |       | 117,000                                          |       | 48,000                                                  |       | 181,500        |       | 164,250        |       | 151,250        |       | 144,000        |       |
| Fixed  Price ($/Bbl)         |       | $                                                 | 90.30      |                                             | $          | 90.30                                                   |       | $              | 90.30      |           | $          | 87.23          |       | $              | 85.65      |   | $ | 85.50 |   | $ | 80.00 |   |

 

54

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***Interest Rate Risks***

 

At December 31,2007, we had debt outstanding of $37.4 million, which incurred interest atfloating rates based on LIBOR in accordance with our reserve-based creditfacility. However, after the closing of our acquisition of oil and natural gasproducing properties in the Permian Basin of West Texas and Southeast NewMexico in January 2008 and other borrowings, our debt outstanding wasincreased to $103.0 million and if the debt remains the same, a 1% increase inLIBOR would result in an estimated $0.4 million increase in annual interestexpense after consideration of the interest rate hedges discussed below. In December 2007and February and March 2008, we entered into interest rate swaps, whichrequire payment to or from the counterparty based upon the differential betweentwo rates for a predetermined contractual amount. This hedging activityconverts a floating interest rate to a fixed interest rate and is intended tomanage our exposure to interest rate fluctuations.

 

The following summarizesinformation concerning our positions in open interest rate swaps applicable toperiods subsequent to December 31, 2007.

 
| ** **                                      | ** ** | **Principal** | ** ** | **Fixed Libor** | ** ** |
|-------------------------------------------------|------------|---------------|------------|----------------------|------------|
| ** **                                      | ** ** | **Balance**   | ** ** | **Rates**            | ** ** |
| Period:                                         | ** ** | ** **    | ** ** | ** **           | ** ** |
| January 1,  2008 to December 10, 2010 |       | $             | 20,000,000 |                 | 3.88       | % |
| January 31,  2008 to January 31, 2011 |       | $             | 30,000,000 |                 | 3.00       | % |
| March 31,  2008 to March 31, 2011     |       | $             | 10,000,000 |                 | 2.66       | % |

 

55

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| **ITEM 8. ** | **FINANCIAL  STATEMENTS AND SUPPLEMENTARY DATA** |
|------------------------|--------------------------------------------------|

 

**Index**

 

Below is an index to theitems contained in Part II, Item 8, Financial Statements andSupplementary Data.

 
|                                                               | **Page** |
|--------------------------------------------------------------------|----------|
| Reports  of Independent Registered Public Accounting Firms         | 57       |
| Consolidated  Balance Sheet                                        | 60       |
| Consolidated  Statement of Operations                              | 61       |
| Consolidated Statement of Members’ Equity                     | 62       |
| Consolidated Statement of Cash Flows                               | 63       |
| Consolidated Statements of Comprehensive Income                    | 64       |
| Notes to Consolidated Financial Statements                         | 65       |
| Supplemental Financial  Information                                |     |
| Supplemental Selected Quarterly Financial Information  (Unaudited) | 78       |
| Supplemental Natural Gas and Oil Operations  (Unaudited)           | 79       |
| Financial Statement  Schedule                                      |     |
| Schedule II —  Valuation and Qualifying Accounts    | 82       |

 

56

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**REPORTOF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM**

 

To the Board of Directors and Unitholders of

Vanguard Natural Resources, LLC

and Subsidiaries

 

We have audited the accompanying consolidated balance sheet ofVanguard Natural Resources, LLC (a Delaware limited liability company) andsubsidiaries (the “Company”) as of December 31, 2007, and the related consolidatedstatements of operations, members’ equity, comprehensive income and cash flowsfor the year then ended. Our audit also included the financial statementschedule listed in the Index in Item 15(a). These consolidated financialstatements and schedule are the responsibility of the Company’s management. Ourresponsibility is to express an opinion on these consolidated financialstatements and

schedule based on our audit.

 

We conducted our audit in accordance with the standards of the PublicCompany Accounting Oversight Board (United States). Those standards requirethat we plan and perform the audit to obtain reasonable assurance about whetherthe consolidated financial statements are free of material misstatement. Anaudit includes examining, on a test basis, evidence supporting the amounts anddisclosures in the consolidated financial statements. An audit also includesassessing the accounting principles used and significant estimates made bymanagement, as well as evaluating the overall financial statement presentation.We believe that our audit provides a reasonable basis for our opinion.

 

In our opinion, the consolidated financial statements referred toabove present fairly, in all material respects, the consolidated financialposition of Vanguard Natural Resources, LLC and subsidiaries as of December 31,2007, and the consolidated results of their operations and their cash flows forthe year then ended, in conformity with accounting principles generallyaccepted in the United States of America. Also in our opinion, the financialstatement schedule, when considered in relation to the basic consolidated financialstatements taken as a whole, presents fairly, in all material respects, theinformation set forth therein.

 

 

/s/ UHY LLP

 

Houston, Texas

March 31, 2008

 

57

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**REPORTOF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM**

 

To the Members of

Vanguard Natural Gas, LLC

and Subsidiaries

 

We have audited theaccompanying consolidated balance sheet of Vanguard Natural Gas, LLC (formerlyNami Holding Company, LLC), and subsidiaries (the “Company”) as of December 31,2006, and the related consolidated statements of operations and cash flows forthe year then ended. These consolidated financial statements are the responsibilityof the Company’s management. Our responsibility is to express an opinion onthese consolidated financial statements based on our audit.

 

We conducted our audit inaccordance with the standards of the Public Company Accounting Oversight Board(United States). Those standards require that we plan and perform the audit toobtain reasonable assurance about whether the consolidated financial statementsare free of material misstatement. An audit includes examining, on a testbasis, evidence supporting the amounts and disclosures in the consolidatedfinancial statements. An audit also includes assessing the accountingprinciples used and significant estimates made by management, as well asevaluating the overall financial statement presentation. We believe that ouraudit provides a reasonable basis for our opinion.

 

In our opinion, theconsolidated financial statements referred to above present fairly, in allmaterial respects, the consolidated financial position of Vanguard Natural Gas,LLC and subsidiaries as of December 31, 2006, and the consolidated resultsof their operations and their cash flows for the year then ended, in conformitywith accounting principles generally accepted in the United States of America.

 

/s/ UHY LLP

 

Houston, Texas

April 20, 2007

 

58

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**Reportof Independent Registered Public Accounting Firm**

 
|   |   | CERTIFIED  PUBLIC

ACCOUNTANTS

 

BUSINESS  ADVISORS

 

TECHNOLOGY

CONSULTANTS |
|--------|--------|---------------------------------------------------------------------------------------------|

 
| To the Members

Vanguard Natural Gas,  LLC |   | 1729  Midpark Road

Suite C-zoo

Knoxville,  TN 37921

 

865.583.0091  phone

865.583.0560  fax

  www.rodefermoss.com |
|--------------------------------------------|--------|-----------------------------------------------------------------------------------------------------------------------------------|

 

We have audited the accompanying consolidatedstatements of operations and cash flows of Vanguard Natural Gas, LLC (formerlyNami Holding Company, LLC) for the year ended December 31, 2005.  These financial statements are theresponsibility of the Company’s management. Our responsibility is to express anopinion on these financial statements based on our audit.

 

We conducted our audit in accordance with thestandards of the Public Company Accounting Oversight Board (United States).Those standards require that we plan and perform the audit to obtain reasonableassurance about whether the financial statements are free of materialmisstatement. The Company has determined that it is not required to have, norwere we engaged to perform, an audit of the Company’s internal control overfinancial reporting. Our audit included consideration of internal control overfinancial reporting as a basis for designing audit procedures that areappropriate in the circumstances, but not for the purpose of expressing anopinion on the effectiveness of the Company’s internal control over financialreporting. Accordingly, we express no such opinion. An audit also includesexamining, on a test basis, evidence supporting the amounts and disclosures inthe financial statements, assessing the accounting principles used andsignificant estimates made by management, as well as evaluating the overallfinancial statement presentation. We believe that our audit provides areasonable basis for our opinion.

 

In our opinion, the financial statementsreferred to above present fairly, in all material respects, the consolidatedresults of Vanguard Natural Gas, LLC’s operations and cash flows for the year endedDecember 31, 2005, in conformity with U.S. generally accepted accountingprinciples.

 

 

Knoxville, Tennessee

April 3, 2007

 

GREENEVILLE - KNOXVILLE - NASHVILLE - TRI-CITIES

 

59

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**VanguardNatural Resources, LLC and Subsidiaries**

**Consolidated Balance Sheet**

**As ofDecember 31,**

** **
| ** **                                                                                        | ** ** | **Vanguard** | ** **  | **Vanguard  Predecessor** | ** ** |
|---------------------------------------------------------------------------------------------------|------------|--------------|-------------|---------------------------|------------|
| ** **                                                                                        | ** ** | **2007**     | ** **  | **2006**                  | ** ** |
| **Assets**                                                                                        | ** ** | ** **   | ** **  | ** **                | ** ** |
| **Current  assets**                                                                               | ** ** | ** **   | ** **  | ** **                | ** ** |
| Cash and cash  equivalents                                                                        |       | $            | 3,109,563   |                      | $          | 1,730,956 |   |
| Trade accounts  receivable, net                                                                   |       | 4,372,731    |        | 5,269,067                 |       |
| Receivables due  from affiliates                                                                  |       | —       |        | 14,650,936                |       |
| Other  receivables                                                                                |       | —       |        | 234,456                   |       |
| Derivative  assets                                                                                |       | 4,017,085    |        | —                    |       |
| Other currents  assets                                                                            |       | 453,198      |        | 283,884                   |       |
| **Total  current assets**                                                                         |       | 11,952,577   |        | 22,169,299                |       |
|                                                                                              |       |         |        |                      |       |
| **Property and equipment**                                                                        | ** ** | ** **   | ** **  | ** **                | ** ** |
| Land                                                                                              |       | —       |        | 46,350                    |       |
| Buildings                                                                                         |       | —       |        | 10,850                    |       |
| Furniture and  fixtures                                                                           |       | 72,893       |        | 846,580                   |       |
| Machinery and  equipment                                                                          |       | 138,719      |        | 12,681,363                |       |
| Less:  accumulated depreciation                                                                   |       | (45,157      | )           | (1,712,535                | )          |
| **Total property and equipment**                                                                  |       | 166,455      |        | 11,872,608                |       |
| ** **                                                                                        | ** ** | ** **   | ** **  | ** **                | ** ** |
| **Natural gas and oil properties, net – full cost  method**                                  |       | 106,983,349  |        | 104,683,610               |       |
|                                                                                              |       |         |        |                      |       |
| **Other assets**                                                                                  | ** ** | ** **   | ** **  | ** **                | ** ** |
| Derivative  assets                                                                                |       | 1,329,511    |        | —                    |       |
| Deferred  financing costs                                                                         |       | 941,833      |        | —                    |       |
| Non-current  deposits                                                                             |       | 8,285,883    |        | —                    |       |
| Other assets                                                                                      |       | 1,519,577    |        | —                    |       |
| **Total assets**                                                                                  |       | $            | 131,179,185 |                      | $          | 138,725,517 |   |
| ** **                                                                                        | ** ** | ** **   | ** **  | ** **                | ** ** |
| **Liabilities and members’ equity**                                                          | ** ** | ** **   | ** **  | ** **                | ** ** |
|                                                                                              |       |         |        |                      |       |
| **Current liabilities**                                                                           | ** ** | ** **   | ** **  | ** **                | ** ** |
| Accounts payable  - trade                                                                         |       | $            | 1,056,627   |                      | $          | 8,756,937 |   |
| Accounts payable  – natural gas and oil                                                      |       | 257,073      |        | 1,441,941                 |       |
| Payables to  affiliates                                                                           |       | 3,838,328    |        | —                    |       |
| Derivative  liabilities                                                                           |       | —       |        | 2,022,079                 |       |
| Accrued expenses                                                                                  |       | 203,159      |        | 1,230,686                 |       |
| Due to member                                                                                     |       | —       |        | 75,000                    |       |
| **Total current liabilities**                                                                     |       | 5,355,187    |        | 13,526,643                |       |
| ** **                                                                                        | ** ** | ** **   | ** **  | ** **                | ** ** |
| Long-term debt                                                                                    |       | 37,400,000   |        | 94,067,500                |       |
| Derivative  liabilities                                                                           |       | 5,903,384    |        | —                    |       |
| Asset retirement  obligations                                                                     |       | 189,711      |        | 418,533                   |       |
| **Total liabilities**                                                                             |       | 48,848,282   |        | 108,012,676               |       |
| ** **                                                                                        | ** ** | ** **   | ** **  | ** **                | ** ** |
| **Commitments and contingencies**                                                                 | ** ** | ** **   | ** **  | ** **                | ** ** |
| ** **                                                                                        | ** ** | ** **   | ** **  | ** **                | ** ** |
| **Members’ equity**                                                                          | ** ** | ** **   | ** **  | ** **                | ** ** |
| Members’  capital, 10,795,000 common units issued and outstanding at December 31,  2007 |       | 90,257,856   |        | 30,712,841                |       |
| Class B  units, 420,000 issued and outstanding at December 31, 2007                     |       | 2,131,995    |        | —                    |       |
| Other  comprehensive loss                                                                         |       | (10,058,948  | )           | —                    |       |
| **Total members’ equity**                                                                    |       | 82,330,903   |        | 30,712,841                |       |
| ** **                                                                                        | ** ** | ** **   | ** **  | ** **                | ** ** |
| **Total liabilities and members’ equity**                                                    |       | $            | 131,179,185 |                      | $          | 138,725,517 |   |

 

See accompanyingnotes to consolidated financial statements.

 

60

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**VanguardNatural Resources, LLC and SubsidiariesConsolidated Statement of Operations**

**For theYears Ended December 31,**
| ** **                                          | ** ** | **Vanguard** | ** ** | **Vanguard  Predecessor** | ** ** |
|-----------------------------------------------------|------------|--------------|------------|---------------------------|------------|
| ** **                                          | ** ** | **2007**     | ** ** | **2006**                  | ** ** | **2005** | ** ** |
| **Revenues**                                        | ** ** | ** **   | ** ** | ** **                | ** ** | ** ** | ** ** |
| Natural gas and  oil sales                          |       | $            | 34,540,500 |                      | $          | 38,849,142 |   | $ | 40,750,089 |   |
| Realized losses  from derivative contracts          |       | (701,675     | )          | (2,207,902                | )          | (10,024,178 | ) |
| Change in fair  value of derivative contracts       |       | —       |       | 17,747,817                |       | (18,778,983 | ) |
| **Total  revenues**                                 |       | 33,838,825   |       | 54,389,057                |       | 11,946,928 |   |
| ** **                                          | ** ** | ** **   | ** ** | ** **                | ** ** | ** ** | ** ** |
| **Costs and expenses**                              | ** ** | ** **   | ** ** | ** **                | ** ** | ** ** | ** ** |
| Lease operating  expenses                           |       | 5,066,230    |       | 4,896,327                 |       | 4,607,198 |   |
| Depreciation,  depletion and amortization           |       | 8,981,179    |       | 8,633,235                 |       | 6,189,478 |   |
| Selling, general  and administrative                |       | 3,506,539    |       | 5,198,760                 |       | 5,945,613 |   |
| Bad debt expense                                    |       | 1,007,458    |       | —                    |       | — |   |
| Taxes other than  income                            |       | 2,053,604    |       | 1,774,215                 |       | 1,248,946 |   |
| **Total  costs and expenses**                       |       | 20,615,010   |       | 20,502,537                |       | 17,991,235 |   |
| ** **                                          | ** ** | ** **   | ** ** | ** **                | ** ** | ** ** | ** ** |
| **Income (loss) from operations**                   |       | 13,223,815   |       | 33,886,520                |       | (6,044,307 | ) |
| ** **                                          | ** ** | ** **   | ** ** | ** **                | ** ** | ** ** | ** ** |
| **Other income (expense)**                          | ** ** | ** **   | ** ** | ** **                | ** ** | ** ** | ** ** |
| Interest income                                     |       | 61,621       |       | 40,256                    |       | 51,471 |   |
| Interest expense                                    |       | (8,134,600   | )          | (7,371,930                | )          | (4,565,712 | ) |
| Loss on  extinguishment of debt expense             |       | (2,501,528   | )          | —                    |       | — |   |
| **Total  other expense**                            |       | (10,574,507  | )          | (7,331,674                | )          | (4,514,241 | ) |
| ** **                                          | ** ** | ** **   | ** ** | ** **                | ** ** | ** ** | ** ** |
| **Net income (loss)**                               |       | $            | 2,649,308  |                      | $          | 26,554,846 |   | $ | (10,558,548 | ) |
| ** **                                          | ** ** | ** **   | ** ** | ** **                | ** ** | ** ** | ** ** |
| Net income per unit:                                |       |         |       |                      |       |   |   |
| Common &  Class B units - basic       |       | $            | 0.24       |                      |       |   |   |   |
| Common &  Class B units - diluted     |       | $            | 0.24       |                      |       |   |   |   |
|                                                |       |         |       |                      |       |   |   |
| Weighted average units outstanding:                 |       |         |       |                      |       |   |   |
| Common units –  basic & diluted       |       | 10,795,000   |       |                      |       |   |   |
| Class B  units – basic & diluted |       | 276,795      |       |                      |       |   |   |

 

See accompanyingnotes to consolidated financial statements.

 

61

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**Vanguard Natural Resources, LLCand Subsidiaries**

**Consolidated Statement ofMembers’ Equity**

**For the Year Ended December 31,2007**

 
| ** **                                                     | ** ** | **Common  Units** | ** ** | **Class B  Units** | ** ** | **Total Members’  Equity** | ** ** |
|----------------------------------------------------------------|------------|-------------------|------------|-------------------------|------------|---------------------------------|------------|
| **Balance****,**January 1, 2007                           |       | —            |       | —                  |       | $                               | —     |   |
| Initial  contribution                                          |       | 5,540,000         |       | —                  |       | 3,289,055                       |       |
| Sale of private  placement units                               |       | —            |       | —                  |       | 41,220,000                      |       |
| Distribution to  member                                        |       | —            |       | —                  |       | (41,220,000                     | )          |
| Issuance of  common units, net of offering costs of $9,804,085 |       | 5,250,000         |       | —                  |       | 89,945,916                      |       |
| Distribution to  members                                       |       | —            |       | —                  |       | (5,626,423                      | )          |
| Unit-based  compensation                                       |       | 5,000             |       | 420,000                 |       | 2,131,995                       |       |
| Net income                                                     |       | —            |       | —                  |       | 2,649,308                       |       |
| Changes in fair  value of commodity hedges                     |       | —            |       | —                  |       | (10,058,948                     | )          |
| ** **                                                     |       |              |       |                    |       |                            |       |
| **Balance****,**December 31, 2007                         |       | 10,795,000        |       | 420,000                 |       | $                               | 82,330,903 |   |

 

See accompanyingnotes to consolidated financial statements.

 

62

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**VanguardNatural Resources, LLC and Subsidiaries**

**ConsolidatedStatement of Cash Flows**

**For theYears Ended December 31,**
| ** **                                                                                | ** ** | **Vanguard** | ** ** | **Vanguard  Predecessor** | ** ** |
|-------------------------------------------------------------------------------------------|------------|--------------|------------|---------------------------|------------|
| ** **                                                                                | ** ** | **2007**     | ** ** | **2006**                  | ** ** | **2005** | ** ** |
| **Operating activities**                                                                  | ** ** | ** **   | ** ** | ** **                | ** ** | ** ** | ** ** |
| Net income  (loss)                                                                        |       | $            | 2,649,308  |                      | $          | 26,554,846 |   | $ | (10,558,548 | ) |
| Adjustments to  reconcile net income (loss) to net cash provided by operating activities: |       |         |       |                      |       |   |   |
| Depreciation,  depletion and amortization                                                 |       | 8,981,179    |       | 8,633,235                 |       | 6,189,478 |   |
| Amortization of  deferred financing costs                                                 |       | 296,115      |       | —                    |       | — |   |
| Bad debt expense                                                                          |       | 1,007,458    |       | —                    |       | — |   |
| Unit-based  compensation                                                                  |       | 2,131,995    |       | —                    |       | — |   |
| Change in fair  value of derivative contracts                                             |       | —       |       | (17,747,817               | )          | 18,778,983 |   |
| Changes in operating  assets and liabilities:                                             |       |         |       |                      |       |   |   |
| Trade accounts  receivable                                                                |       | (504,683     | )          | 1,634,402                 |       | (127,911 | ) |
| Receivables due  from affiliates                                                          |       | (530,809     | )          | (3,448,823                | )          | (8,488,293 | ) |
| Price risk  management activities, net                                                    |       | (11,524,239  | )          | —                    |       | — |   |
| Other  receivables                                                                        |       | —       |       | 1,004,464                 |       | (989,545 | ) |
| Inventory                                                                                 |       | —       |       | (54,988                   | )          | (51,371 | ) |
| Other current  assets                                                                     |       | (340,060     | )          | 40,803                    |       | 91,098 |   |
| Accounts payable                                                                          |       | 1,243,817    |       | 373,381                   |       | 6,638,940 |   |
| Accrued expenses                                                                          |       | (2,037,794   | )          | (902,185                  | )          | (952,988 | ) |
| **Net cash provided by operating activities**                                             |       | 1,372,287    |       | 16,087,318                |       | 10,529,843 |   |
| ** **                                                                                | ** ** | ** **   | ** ** | ** **                | ** ** | ** ** | ** ** |
| **Investing activities**                                                                  | ** ** | ** **   | ** ** | ** **                | ** ** | ** ** | ** ** |
| Additions to  property and equipment                                                      |       | (132,371     | )          | (8,486,055                | )          | (2,694,185 | ) |
| Additions to  natural gas and oil properties                                              |       | (12,821,192  | )          | (28,896,671               | )          | (34,373,612 | ) |
| Acquisitions of  natural gas and oil properties                                           |       | (3,649,702   | )          | —                    |       | — |   |
| Deposits and  prepayments of natural gas and oil properties                               |       | (9,805,460   | )          | —                    |       | — |   |
| **Net cash used in investing activities**                                                 |       | (26,408,725  | )          | (37,382,726               | )          | (37,067,797 | ) |
| ** **                                                                                | ** ** | ** **   | ** ** | ** **                | ** ** | ** ** | ** ** |
| **Financing activities**                                                                  | ** ** | ** **   | ** ** | ** **                | ** ** | ** ** | ** ** |
| Proceeds from  borrowings                                                                 |       | 126,200,000  |       | 21,360,000                |       | 30,390,000 |   |
| Repayment of  debt                                                                        |       | (182,867,500 | )          | —                    |       | — |   |
| Proceeds from  sale of initial public offering units                                      |       | 89,946,916   |       | —                    |       | — |   |
| Proceeds from  private placement units                                                    |       | 41,220,000   |       | —                    |       | — |   |
| Capital  distributions                                                                    |       | (46,846,423  | )          | (1,375,104                | )          | (4,819,333 | ) |
| Financing costs                                                                           |       | (1,237,948   | )          | —                    |       | — |   |
| **Net cash provided by financing activities**                                             |       | 26,415,045   |       | 19,984,896                |       | 25,570,667 |   |
| **Net increase (decrease) in cash and cash  equivalents**                                 |       | 1,378,607    |       | (1,310,512                | )          | (967,287 | ) |
| **Cash and cash equivalents,**beginning of year                                           |       | 1,730,956    |       | 3,041,468                 |       | 4,008,755 |   |
| **Cash and cash equivalents,**end of year                                                 |       | $            | 3,109,563  |                      | $          | 1,730,956 |   | $ | 3,041,468 |   |
| **Supplemental cash flow information:**                                                   | ** ** | ** **   | ** ** | ** **                | ** ** | ** ** | ** ** |
| Cash paid for  interest                                                                   |       | $            | 8,839,169  |                      | $          | 7,233,549 |   | $ | 5,735,952 |   |
| **Non-cash  financing and investing activities:**                                         | ** ** | ** **   | ** ** | ** **                | ** ** | ** ** | ** ** |
| Asset retirement  obligations                                                             |       | $            | 177,153    |                      | $          | 187,638 |   | $ | 69,900 |   |
| Initial  contribution of assets                                                           |       | $            | 3,289,055  |                      | $          | — |   | $ | — |   |

 

See accompanyingnotes to consolidated financial statements.

 

63

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**Vanguard Natural Resources, LLC and SubsidiariesConsolidated Statement of Comprehensive Income**

**For the Years Ended December 31,**

 
| ** **                                                  | ** ** | **Vanguard** | ** ** | **Vanguard  Predecessor** | ** ** |
|-------------------------------------------------------------|------------|--------------|------------|---------------------------|------------|
| ** **                                                  | ** ** | **2007**     | ** ** | **2006**                  | ** ** | **2005** | ** ** |
|                                                        |       |         |       |                      |       |   |   |
| **Net income (loss)**                                       |       | $2,649,308   |       | $26,554,846               |       | $(10,558,548 | ) |
|                                                        |       |         |       |                      |       |   |   |
| Net losses from  cash flow hedging activities:              |       |         |       |                      |       |   |   |
| Unrealized  mark-to-market losses arising during the period |       | (9,644,224   | )          | —                    |       | — |   |
| Reclassification  of realized losses                        |       | (414,724     | )          | —                    |       | — |   |
| Other  comprehensive loss                                   |       | (10,058,948  | )          | —                    |       | — |   |
|                                                        |       |         |       |                      |       |   |   |
| **Comprehensive income (loss)**                             |       | $(7,409,640  | )          | $26,554,846               |       | $(10,558,548 | ) |

 

See accompanyingnotes to consolidated financial statements.

 

64

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** **

**Vanguard Natural Resources, LLCand Subsidiaries**

**Notesto Consolidated Financial Statements**

**December 31,2007**

 

**1.    Basis of Presentation and SignificantAccounting Policies**

 

**Basisof Presentation and Nature of Operations**

 

Vanguard NaturalResources, LLC is a publicly traded limited liability company focused on theacquisition, development and exploitation of mature, long-lived natural gas andoil properties. Through our operating subsidiaries, we own properties in thesouthern portion of the Appalachian Basin, primarily in southeast Kentucky andnortheast Tennessee.

 

References in this report to (1) “us”, “we”, “our”,“the Company”, “Vanguard” or “VNR” are to Vanguard Natural Resources, LLC andits subsidiaries, including Vanguard Natural Gas, LLC (“VNG”), Trust EnergyCompany, LLC, (“TEC”), VNR Holdings, Inc (“VNRH”) and Ariana Energy, LLC, (“ArianaEnergy”) and (2) “Vanguard Predecessor”, “Predecessor”, “our operatingsubsidiary” or “VNG” are to Vanguard Natural Gas, LLC.

 

We were formed in October 2006and effective January 5, 2007, Vanguard Natural Gas, LLC (formerly NamiHolding Company, LLC) was separated into our operating subsidiary and VinlandEnergy Eastern, LLC (“Vinland”). As part of the separation, we retained all ofour Predecessor’s proved producing wells and associated reserves. We alsoretained 40% of our Predecessor’s working interest in the known producinghorizons in approximately 95,000 gross undeveloped acres and a contract rightto receive approximately 99% of the net proceeds from the sale of productionfrom certain producing gas and oil wells. In the separation, Vinland wasconveyed the remaining 60% of our Predecessor’s working interest in the knownproducing horizons in this acreage, and 100% of our Predecessor’s workinginterest 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 thewells that we drill in this area. We refer to these events as the “Restructuring.”

 

In October 2007, wecompleted our initial public offering (“IPO”) of 5.25 million unitsrepresenting limited liability interests in VNR at $19.00 per unit for netproceeds of $92.8 million after deducting underwriting discounts and fees of$7.0 million.  The proceeds were used toreduce indebtedness under our Credit Facility by $80.0 million and the balancewas used for the payment of accrued distributions to pre-IPO unitholders andthe payment of a deferred swap obligation.

 

VNG was formed inKentucky on December 15, 2004 and its principal business is to holdinterests in TEC, VNRH and Ariana Energy. TEC was formed in Kentucky on December 15,2004. Its principal business consists of natural gas and oil development andexploitation of mature, long-lived natural gas and oil properties in theAppalachian region of eastern Kentucky. VNRH was formed in Delaware on March 28,2007.  Its principal business it toprovide general employment related services, including payroll and employmentadministration, as well as information technology and communication services toVNR.  Ariana Energy was formed inTennessee on April 26, 2002 and its principal business consists of naturalgas and oil development and exploitation of mature, long-lived natural gas andoil properties in Tennessee.

 

The consolidated financialstatements as of and for the year ended December 31, 2007 include theaccounts of VNG, TEC, VNRH and Ariana Energy. In conjunction with theRestructuring, Nami Resources Company, LLC conveyed its assets to Vinland orTEC as appropriate and is no longer a wholly-owned subsidiary of VNG andtherefore is no longer consolidated in these consolidated financialstatements.  The consolidated financialstatements as of December 31, 2006 and for the year ended December 31,2006 and 2005 are based on the annual audited financial statements of VNG priorto the Restructuring.  As such, theseperiods are labeled Vanguard Predecessor and are separated from VNR financialdata by a bold black line.

 

Our consolidatedfinancial statements are prepared in accordance with U.S. generallyaccepted accounting principles and include the accounts of all subsidiariesafter the elimination of all significant intercompany accounts andtransactions.  Additionally, ourfinancial statements for prior periods include reclassifications that were madeto conform to the current period presentation. Those reclassifications did notimpact our reported net income or member’s equity.

 

**NewAccounting Pronouncements Issued But Not Yet Adopted**

 

In September 2006,the Financial Accounting Standards Board (FASB) issued Statement of FinancialAccounting Standards No. 157 “*Fair Value Measurements*”(SFAS 157). SFAS 157 introduces a framework for

 

65

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**Vanguard Natural Resources, LLCand Subsidiaries**

**Notesto Consolidated Financial Statements**

**December 31, 2007**

 

measuring fair value andexpands required disclosure about fair value measurements of assets andliabilities. On February 6, 2008, the FASB issued a final FASB StaffPosition (FSP) No. FAS 157-b, “*Effective Date of FASBStatement No. 157*”. This FSP delays the effective date of FASBStatement No. 157, *Fair ValueMeasurements,*for all non-financial assets and non-financialliabilities, except those that are recognized or disclosed at fair value in thefinancial statements on a recurring basis. In addition, the FSP removes certainleasing transactions from the scope of SFAS 157. The effective date of SFAS 157for non-financial assets and liabilities has been delayed by one year to fiscalyears beginning after November 15, 2008 and interim periods within thosefiscal years. SFAS 157 for financial assets and liabilities is effective forfiscal years beginning after November 15, 2007, and the Company adoptedthe standard for those assets and liabilities as of January 1, 2008. Theprincipal impact to the Company will be to require the Company to expand itsdisclosure regarding its derivative instruments and to include credit risk as apart of the calculation of the fair value of derivatives. The adoption of thisstandard did not have a material impact on the consolidated financialstatements.

 

In February 2007,the FASB issued SFAS No. 159, “*The FairValue Option for Financial Assets and Financial Liabilities, including anamendment of FASB Statement No. 115* ” (“SFAS 159”), whichpermits companies to choose, at specified dates, to measure certain eligiblefinancial instruments at fair value. The objective of SFAS 159 is toreduce volatility in preparer reporting that may be caused as a result ofmeasuring related financial assets and liabilities differently and to expandthe use of fair value measurements. The provisions of SFAS 159 apply onlyto entities that elect to use the fair value option and to all entities withavailable-for-sale and trading securities. Additional disclosures are alsorequired for instruments for which the fair value option is elected.SFAS 159 is effective for fiscal years beginning after November 15,2007. No retrospective application is allowed, except for companies that chooseto adopt early. At the effective date, companies may elect the fair valueoption for eligible items that exist at that date, and the effect of the firstremeasurement to fair value must be reported as a cumulative-effect adjustmentto the opening balance of retained earnings. Effective January 1, 2008,the Company adopted, SFAS No.159 and the adoption did not have a materialimpact on its consolidated financial statements.

 

In December 2007,the FASB issued SFAS No. 141 (revised 2007), *“Business Combinations”*(“SFAS 141(R)”), which replaces FASBStatement No. 141. SFAS 141(R) establishes principles andrequirements for how an acquirer recognizes and measures in its financialstatements the identifiable assets acquired, the liabilities assumed, anynon-controlling interest in the acquiree and the goodwill acquired. TheStatement also establishes disclosure requirements that will enable users toevaluate the nature and financial effects of the business combination. SFAS 141(R) iseffective for acquisitions that occur in an entity’s fiscal year that beginsafter December 15, 2008, which will be our fiscal year 2009. The impact,if any, will depend on the nature and size of business combinations that weconsummate after the effective date.

 

In December 2007,the FASB issued SFAS No. 160, *“Non-controllingInterests in Consolidated Financial statements—an amendment of ARB No. 51”*(“SFAS 160”). SFAS 160 requires that accounting and reporting forminority interests will be recharacterized as non-controlling interests andclassified as a component of equity. SFAS 160 also establishes reportingrequirements that provide sufficient disclosures that clearly identify anddistinguish between the interests of the parent and the interests of thenon-controlling owners. SFAS 160 applies to all entities that prepareconsolidated financial statements, except not-for-profit organizations, butwill affect only those entities that have an outstanding non-controllinginterest in one or more subsidiaries or that deconsolidate a subsidiary. Thisstatement is effective as of the beginning of an entity’s first fiscal yearbeginning after December 15, 2008, which will be our fiscal year 2009.Based upon the December 31, 2007 balance sheet, the statement would haveno impact.

 

In March 2008, theFASB issued SFAS No. 161, “*Disclosuresabout Derivative Instruments and Hedging Activities”*(*“*SFAS No. 161”). SFAS No. 161 is intended to improve financialreporting about derivative instruments and hedging activities by requiringenhanced disclosures to enable investors to better understand their effects onan entity’s financial position, financial performance, and cash flows. SFAS No. 161achieves these improvements by requiring disclosure of the fair values ofderivative instruments and their gains and losses in a tabular format. It alsoprovides more information about an entity’s liquidity by requiring disclosure ofderivative features that are credit risk-related. Finally, it requirescross-referencing within footnotes to enable financial statement users tolocate important information about derivative instruments. SFAS No. 161 iseffective for financial statements issued for fiscal years and interim periodsbeginning after November 15, 2008, with early application encouraged. Weare evaluating the impact of SFAS No. 161 on our consolidated financialstatements and do not expect the impact of implementation to be material.

 

66

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**Vanguard Natural Resources, LLCand Subsidiaries**

**Notes to Consolidated FinancialStatements**

**December 31, 2007**

 

**Cash Equivalents**

 

TheCompany considers all highly liquid short-term investments with originalmaturities of three months or less to be cash equivalents.

 

**AccountsReceivable and Allowance for Doubtful Accounts**

 

Accountsreceivable are customer obligations due under normal trade terms and arepresented on the consolidated balance sheet net of allowances for doubtfulaccounts. We establish provisions for losses on accounts receivable if wedetermine that we will not collect all or part of the outstanding balance. Weregularly review collectibility and establish or adjust our allowance asnecessary using the specific identification method.

 

**Inventory**

 

Materials,supplies and commodity inventories are valued at the lower of cost or market.The cost is determined using the first-in, first-out method.

 

**Propertyand Equipment**

 

Propertyand equipment is recorded at cost. Major property additions, replacements andbetterments are capitalized, while maintenance and repairs that do not extendthe useful life of an asset are expensed as incurred. Depreciation is recordedusing the straight-line method over the respective estimated useful lives ofour assets.

 

The estimateduseful lives of our property and equipment are as follows:

 
| ** **                       | ** ** | **Lives  (Years)**                                            | ** ** |
|----------------------------------|------------|---------------------------------------------------------------|------------|
| Furniture and fixtures | ** ** | 3-5                                                           | ** ** |
| Machinery and  equipment         |       | 7           |       |

 

Depreciationexpense for the year ended December 31, 2007 was $36,539. Our Predecessor’sconsolidated statement of operations included depreciation expense in theamount of $693,266, and $485,121 at December 31, 2006 and 2005,respectively.

 

**NaturalGas and Oil Properties**

 

Thefull cost method of accounting is used to account for natural gas and oilproperties. Under the full cost method, substantially all costs incurred in connectionwith the acquisition, development and exploration of natural gas and oilreserves are capitalized. These capitalized amounts include the costs ofunproved properties, internal costs directly related to acquisitions,development and exploration activities, asset retirement costs and capitalizedinterest. Under the full cost method, both dry hole costs and geological andgeophysical costs are capitalized into the full cost pool, which is subject toamortization and subject to ceiling test limitations as discussed below.

 

Capitalizedcosts associated with proved reserves are amortized over the life of thereserves using the unit of production method. Conversely, capitalized costsassociated with unproved properties are excluded from the amortizable baseuntil these properties are evaluated, which occurs on a quarterly basis.Specifically, costs are transferred to the amortizable base when properties aredetermined to have proved reserves. In addition, we transfer unproved propertycosts to the amortizable base when unproved properties are evaluated as beingimpaired and as exploratory wells are determined to be unsuccessful.Additionally, the amortizable base includes estimated future development costs,dismantlement, restoration and abandonment costs net of estimated salvagevalues, and geological and geophysical costs incurred that cannot be associatedwith unevaluated properties or prospects in which we own a direct interest.

 

Capitalizedcosts are limited to a ceiling based on the present value of future netrevenues using end of period spot prices discounted at 10%, plus the lower ofcost or fair market value of unproved properties. If the ceiling is not greaterthan or equal to the total capitalized costs, we are required to write-downcapitalized costs to the ceiling. We perform this ceiling test calculation eachquarter. Any required write-downs are included in the consolidated statement ofoperations as a ceiling test charge. Ceiling test calculations include theeffects of derivative contracts. Ceiling test calculations exclude theestimated future cash outflows associated with asset retirement obligationsrelated to proved developed reserves.

 

Whenwe sell or convey interests in natural gas and oil properties, they reducenatural gas and oil reserves for the amount attributable to the sold orconveyed interest. We do not recognize a gain or loss on sales of natural gas andoil properties, unless those sales would significantly alter the relationshipbetween capitalized costs and proved reserves. Sales proceeds on insignificantsales are treated as an adjustment to the cost of the properties.

 

67

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**Vanguard Natural Resources, LLCand Subsidiaries**

**Notes to Consolidated FinancialStatements**

**December 31, 2007**

 

**AssetRetirement Obligations**

 

UnderSFAS No. 143*, Accounting for AssetRetirement Obligations,*we record a liability for asset retirementobligations at fair value in the period in which the liability is incurred if areasonable estimate of fair value can be made. The associated asset retirementcost is capitalized as part of the carrying amount of the long-lived asset.Subsequently, the asset retirement cost is allocated to expense using asystematic and rational method over the assets useful life. Our recognizedasset retirement obligation exclusively relates to the plugging and abandonmentof natural gas and oil wells. Management periodically reviews the estimate ofthe timing of well abandonments as well as the estimated plugging andabandonment costs, which are discounted at the credit adjusted risk freerate.  These retirement costs arerecorded as a long-term liability on the consolidated balance sheet with anoffsetting increase in natural gas and oil properties. An ongoing accretionexpense is recognized for changes in the value of the liability as a result ofthe passage of time, which we record in depreciation, depletion andamortization expense in the consolidated statement of operations.

 

**Impairmentof Long-Lived Assets**

 

Weevaluate the carrying value of long-lived assets, other than investments innatural gas and oil properties, when events or changes in circumstancesindicate that the carrying value of such assets may not be recoverable. Forproperty and equipment used in operations, the determination of impairment isbased upon expectations of undiscounted future cash flows, before interest, ofthe related asset. If the carrying value of the asset exceeds the undiscountedfuture cash flows, the impairment would be computed as the difference betweenthe carrying value of the asset and the fair value.

 

**RevenueRecognition and Gas Imbalances**

 

Weapply the sales method of accounting for natural gas and oil revenue. Underthis method, revenues are recognized based on the actual volume of natural gasand oil sold to customers, net of any royalty interests owed on the soldproduct. In the movement of natural gas, it is common for differences to arisebetween the volume of gas contracted or nominated, and the volume of gasactually received or delivered. These variances or imbalances, are the resultof certain attributes of the natural gas commodity and the industry itself.Consequently, the credit given by a pipeline for volumes received fromproducers may be different than volumes actually delivered by a pipeline. Whenall necessary information, such as the final pipeline statement for receiptsand deliveries are available, the imbalances are resolved and adjustments tothe trade accounts receivable or trade accounts payable is recorded as appropriate.  The amount of imbalances were not material atDecember 31, 2007 and 2006.

 

**Concentrationof Credit Risk**

 

Financialinstruments that potentially subject us to concentrations of credit riskconsist principally of cash and cash equivalents, accounts receivable andderivative contracts. We control our exposure to credit risk associated withthese instruments by (i) placing our assets and other financial interestswith credit-worthy financial institutions and (ii) maintaining policiesover credit extension that include the evaluation of customers’ financialcondition and monitoring payment history, although we do not have collateralrequirements.

 

At December 31,2007 and 2006, the cash and cash equivalents are concentrated in two financialinstitutions. We periodically assess the financial condition of theseinstitutions and believe that any possible credit risk is minimal. At December 31,2007 and 2006, seven and six customers comprised 87% and 90% of our total tradeaccounts receivable, respectively. This concentration of customers may impactthe overall exposure to credit risk in that the customers are in the energyindustry and they may be similarly affected by changes in economic or otherconditions. In addition, receivables due from affiliates represented 66% oftotal current assets at December 31, 2006. All of the related partybalances at December 31, 2006, were conveyed to other entities pursuant tothe Restructuring and therefore no receivable balances were outstanding fromthese affiliates at December 31, 2007.

 

**Use of Estimates**

 

The preparation of financial statements inconformity with accounting principles generally accepted in the Unites Statesof America requires management to make estimates and assumptions that affectthe reported amounts of assets and liabilities and disclosure of contingentassets and liabilities at the date of the financial statements and the reportedamounts of revenues and expenses during the reporting period. The mostsignificant estimates pertain to proved natural gas and oil reserves andrelated cash flow estimates used in impairment tests of natural gas and oilproperties, the fair value of derivative contracts and asset retirementobligations, natural gas and oil revenues and expenses, as well as estimates ofexpenses related to depreciation, depletion and amortization.  Actual results could differ from thoseestimates.

 

68

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**Vanguard Natural Resources, LLCand Subsidiaries**

**Notes to Consolidated FinancialStatements**

**December 31,2007**

 

**PriceRisk Management Activities**

 

Fromtime to time, the Company enters into derivative contracts, such as natural gasand oil swaps, collars and put option contracts, as a hedging strategy tomanage commodity price risk associated with its production. Gains and losses onthese hedging activities are generally recognized over the period that itsproduction is hedged as an offset to the specific hedged item. Cash flowsrelated to any recognized gains and losses associated with these hedges are reportedas cash flows from operations. Changes in derivative fair values that aredesignated as hedges are deferred in other comprehensive income (loss) to theextent that they are effective and then recognized in operating revenues whenthe hedged transactions occur. The ineffective portion of a hedge’s change invalue and the change in value of all derivative contracts not designated ashedges is recognized immediately in earnings as a separate line item in ourconsolidated statement of operations.

 

Werecord all derivative contracts on the consolidated balance sheet at fair valueas either short-term or long-term assets or liabilities based upon theiranticipated settlement date. We net derivative assets and liabilities forcounterparties where we have a legal right of offset. The derivative contractsentered into in 2006 and 2005 were not specifically designated as hedges underSFAS No. 133, *Accounting for DerivativeInstruments and Hedging Activities* and therefore did not qualify forhedge accounting treatment. The change in fair value of these derivativecontracts is recorded in the consolidated statement of operations.

 

**IncomeTaxes**

 

TheCompany is treated as a partnership for federal and state income taxpurposes.  As such, it is not a taxableentity and does not directly pay federal and state income tax. Its taxableincome or loss, which may vary substantially from the net income or net lossreported in the consolidated statement of operations , is included in thefederal and state income tax returns of each unitholder.  Accordingly, no recognition has been given tofederal and state income taxes for the operations of the Company.  The aggregate difference in the basis of netassets for financial and tax reporting purposes cannot be readily determined asthe Company does not have access to information about each unitholders’ taxattributes in the Company.

 

**2.   ****Accounts Receivable and Allowance for Doubtful Accounts**

 

Weestablished an approximate $1.0 million provision for a loss on the entireamount due from a customer which filed for protection under Chapter 11 of theBankruptcy Code in May 2007.  Theaccount receivable was due from oil sales through December 2006 at whichtime we ceased selling oil to the customer. As the amount of any potentialrecovery is uncertain, we elected to reserve the entire balance and it isreflected as bad debt expense on our consolidated statement of operations forthe year ended December 31, 2007. We began selling our oil production to anew customer beginning in March 2007. There are no allowances for doubtfulaccounts recorded against accounts receivable at December 31, 2006.

 

**3.    OtherReceivables**

 

Fromtime to time, our Predecessor advanced funds to third parties, primarily forthe purpose of providing financing related to the purchase of drilling rigs orother related equipment. Amounts due from such parties amounted to $234,456 at December 31,2006.  These receivables werenon-interest bearing and due on demand. All other receivable balances at December 31,2006, were conveyed to other entities pursuant to the Restructuring andtherefore no other receivable balances were outstanding at December 31,2007.

 

69

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**Vanguard Natural Resources, LLCand Subsidiaries**

**Notes to Consolidated FinancialStatements**

**December 31,2007**

 

**4.    NaturalGas and Oil Properties**

 

Naturalgas and oil properties are comprised of the following:

 

| ** **                                                            | ** ** | **Vanguard** | ** **  | **Vanguard  Predecessor** | ** ** |
|-----------------------------------------------------------------------|------------|--------------|-------------|---------------------------|------------|
| **December 31,**                                                 | ** ** | **2007**     | ** **  | **2006**                  | ** ** |
| Natural gas and oil properties, at cost |       | $            | 135,435,240 |                      | $          | 128,811,908 |   |
| Accumulated  depletion                                                |       | (28,451,891  | )           | (24,128,298               | )          |
| Natural gas and  oil properties, net                                  |       | $            | 106,983,349 |                      | $          | 104,683,610 |   |

 

**5.    CreditFacilities and Long-Term Debt**

 

Our creditfacilities and long-term debt consisted of the following at December 31,:

 
| ** **      | ** **                                         | ** **             | ** ** | ** **             | ** **                 | **Vanguard** | ** ** | **Vanguard  Predecessor** | ** ** |
|-----------------|----------------------------------------------------|------------------------|------------|------------------------|----------------------------|--------------|------------|---------------------------|------------|
| **Description** | ** **                                         | **Interest Rate** | ** ** | **Maturity Date** | ** **                 | **2007**     | ** ** | **2006**                  | ** ** |
| $               | 75  million Senior Secured Revolver |                   | Variable   |                   | January 31, 2007 |         | $          | —                    |       | $ | 63,067,500 |   |
| $               | 40 million TCW  Senior Secured Notes               |                   | 13%        |                   | December 29, 2011     |         | —     |                      | 31,000,000 |   |
| $               | 200 million  Senior Secured Revolver               |                   | Variable   |                   | January 3, 2011       |         | 37,400,000 |                      | —     |   |
| Total           |                                               |                   |       |                   |                       | $            | 37,400,000 |                      | $          | 94,067,500 |   |

 

***$75 million Senior Secured Revolver***

 

OnJune 30, 2003, we entered into a $75.0 million senior secured revolvingcredit facility with the Bank of Texas (“Senior Revolver”) which amended andrestated in its entirety a loan agreement dated March 23, 2001. The SeniorRevolver had an original maturity date of June 30, 2006 but was extendedthrough amendments to January 31, 2007. The available credit line (“BorrowingBase”) was subject to adjustment from time to time but not less than on asemi-annual basis based on the projected discounted present value (asdetermined by independent petroleum engineers) of estimated future net cashflows from certain proved natural gas and oil reserves of the Company. At December 31,2006, the Borrowing Base was $65.0 million. The Senior Revolver was secured bya mortgage lien on certain natural gas and oil properties, field equipment andaccounts receivable, among other assets held by the Company. Interest ratesunder this credit facility were at the election of the Company based onEuro-Dollars (LIBOR) or Stated Rate (Prime) indications, plus a margin. Themargin could range from Prime minus 0.25% to Prime plus 0.25% or LIBOR plus1.875% to LIBOR plus 2.625% depending on borrowing base utilization. At December 31,2006, our interest rate was 8.5%. The availability of borrowings was subject tovarious conditions, which included compliance with the financial covenants andratios required by the facility, absence of default under the facility and thecontinued accuracy of the representations and warranties contained in thefacility. At December 31, 2006, the financial coverage ratios under thefacility required that our debt to EBITDA (as defined in the loan agreement)ratio not exceed 4.0 to 1.0 and our current ratio (as defined in the loanagreement) not be less than 1.0 to 1.0. In addition, affiliate investments (asdefined in the loan agreement) could not exceed $10.0 million.

 

Sincethe inception of the Senior Revolver, seven amendments were entered into whichamended certain terms of the loan agreement including increasing the number ofparticipating lenders, changing the maximum borrowing base, extending thematurity date, reducing the interest costs, adding a new financial covenant andadding new reporting requirements. In addition, on December 30, 2004, oursecond amendment reduced the amount of natural gas and oil properties pledgedunder the Senior Revolver. Certain pledged natural gas and oil properties werereleased so that they could be pledged under a new $40.0 million note facilityas described below. As consideration for releasing the pledged properties,indebtedness under the Senior Revolver was reduced by $16.0 million usingproceeds from the new note facility.

 

OnJanuary 3, 2007, all amounts due under the Senior Revolver were repaid anda new long-term credit facility was established as discussed below, andtherefore, amounts due under the Senior Revolver are reported on the balancesheet as a long-term obligation despite the maturity date falling within oneyear of December 31, 2006.

 

***$40 million TCW Senior Secured Notes***

 

OnDecember 30, 2004, we entered into a $40.0 million Senior Secured Notesfacility due to TCW Asset Management Company (the “TCW Notes”). The TCW Notesoriginal maturity was on December 29, 2011 and required quarterly interestpayments at 13% per annum. The TCW Notes were secured by a mortgage lien on certainnatural gas and oil properties. Prior to December 30, 2006, theavailability of borrowings was subject to various conditions, which includedcompliance with the financial covenants and ratios required by the facility,absence of default under the facility and the continued accuracy of therepresentations and warranties contained in the facility. 

 

70

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**Vanguard Natural Resources, LLCand Subsidiaries**

**Notes to Consolidated FinancialStatements**

**December 31, 2007**

 

AfterDecember 30, 2006, no new borrowings were available. At December 31,2006, the financial coverage ratios under the facility required that ourcollateral coverage ratio (as defined in the loan agreement) not be less than1.2 to 1.0 and our current ratio (as defined in the loan agreement) not be lessthan 1.0 to 1.0. We could not borrow, repay, and reborrow under the facility.Optional prepayments were not permitted prior to December 31, 2006 andwere subject to a range of penalties thereafter until December 31, 2008 atwhich point no prepayment penalties applied.

 

OnJanuary 3, 2007, all amounts due under the TCW Notes were repaid and a newcredit facility was established as discussed below.  We recorded a $2.5 million loss on theextinguishment of this debt as the loan agreement required an early prepaymentpenalty.

 

***New******$200 Million Senior Secured Revolver***

 

In January 2007,we entered into a new four-year $200.0 million revolving credit facility (“CreditFacility”) with two banks. All outstanding debt under the TCW Notes (includingan early payment penalty of $2.5 million) and the Senior Revolver were repaidwith borrowings under the new Credit Facility. The available credit line (“BorrowingBase”) is subject to adjustment from time to time but not less than on asemi-annual basis based on the projected discounted present value (asdetermined by independent petroleum engineers) of estimated future net cashflows from certain proved natural gas and oil reserves. The initial BorrowingBase was set at $115.5 million and is secured by a first lien security interestin all of our natural gas and oil properties. However, the borrowing base was subject to a $1.0 million reduction permonth starting on July 1, 2007 through November 1, 2007.  In November 2007, with the sixthamendment to the Credit Facility, our borrowing base under our Credit Facilitywas set at $110.5 million pursuant to our semi-annual redetermination.

 

Interest ratesunder the Credit Facility are based on Euro-Dollars (LIBOR) or ABR (Prime)indications, plus a margin. The applicable margin and other fees increase asthe utilization of the borrowing base increases. Pursuant to the sixthamendment to the Credit Facility, the applicable margins on our borrowing baseutilization grid were lowered to reflect the following:

 

**Borrowing Base Utilization Grid**

** **
| **Borrowing  Base Utilization Percentage** | *** *** | ***<25%*** | *** *** | ***>25%  <50%*** | *** *** | ***>50%  <75%*** | *** *** | ***>75%*** | *** *** |
|--------------------------------------------|--------------|---------------|--------------|------------------------|--------------|------------------------|--------------|---------------|--------------|
| Eurodollar Loans                           |         | 1.000%        |         | 1.250%                 |         | 1.500%                 |         | 1.750%        |         |
| ABR Loans                                  |         | 0.000%        |         | 0.250%                 |         | 0.500%                 |         | 0.750%        |         |
| Commitment Fee  Rate                       |         | 0.250%        |         | 0.300%                 |         | 0.375%                 |         | 0.375%        |         |
| Letter of Credit  Fee                      |         | 1.000%        |         | 1.250%                 |         | 1.500%                 |         | 1.750%        |         |

 

The CreditAgreement contains a number of customary covenants that require us to maintaincertain financial ratios, limit our ability to incur additional debt, sellassets, create liens, or make certain distributions. At December 31, 2007,we were in compliance with our debt covenants. In addition, after consideration of the third amendment to the CreditFacility described below, the first $100.0 million of proceeds received from anequity infusion were to be applied to the repayment of borrowings under theCredit Facility (“Equity Event”). Pursuant to the fifth amendment, the amount of proceeds from the equity eventthat was to be applied to the repayment of borrowings under the Credit Facilitywas reduced from $100.0 million to $80.0 million. Since borrowings underthe Credit Facility were not reduced by $100.0 million by July 1, 2007,the applicable margin increased as follows:

 
| Eurodollar Loans      |   | 3.00 | % |
|-----------------------|--------|------|---|
| ABR Loans             |   | 4.00 | % |
| Commitment Fee  Rate  |   | 0.50 | % |
| Letter of Credit  Fee |   | 3.00 | % |

 

The CreditAgreement required us to enter into a commodity price hedge positionestablishing certain minimum fixed prices for anticipated future productionequal to approximately 84% of the projected production from proved developedproducing reserves from the second half of 2007 through 2011. Also, the CreditAgreement required that certain production put option contracts for the years2007, 2008 and 2009 be put in place to create a price floor for anticipatedproduction from new wells drilled.  See *Note 6. Financial Instruments and Price Risk Management Activities*for further discussion.

 

71

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**Vanguard Natural Resources, LLC andSubsidiaries**

**Notes to Consolidated FinancialStatements**

**December 31, 2007**

 

In March 2007,the first amendment to the Credit Facility was executed. The amendmentredefined the method to calculate a financial covenant to include the impact ofacquisitions and divestitures. In addition, it clarified that the increase inthe applicable margin, which commenced on July 1, 2007, will continue onlyuntil the Equity Event occurs.

 

In April 2007,the second amendment to the Credit Facility was executed. The amendmentredefined change of control to allow for the sale of common units to privateinvestors more fully described below in *Note 10. Common Units andNet Income per Unit*, recognized certain contract rights to receiveapproximately 99% of the net proceeds (after deducting royalties paid to otherparties, severance taxes, third-party transportation costs, costs incurred inthe operation of the wells and overhead costs) from the sale of production fromcertain producing gas and oil wells located within the Asher lease.

 

In May 2007,the third amendment to the Credit Facility was executed. The amendmentincreased the amount of proceeds from an equity infusion that must be appliedto the repayment of borrowings under the Credit Facility from $80.0 million to$100.0 million. A new Minimum Liquidity covenant was added which requires us tomaintain unencumbered liquid assets of at least $2.0 million which includesunused availability under the borrowing base. Also, the amount of other debt wecan incur was temporarily increased from $1.0 million to $7.5 million whichallowed us to incur the debt necessary to reset our 2007, 2008 and 2009 naturalgas swaps at higher prices more fully described in *Note 6.Financial Instruments and Price Risk Management Activities*.  The other debt was required to be repaid atthe earlier of five business days after closing of a public offering of equitysecurities or September 3, 2007. This date was extended to November 1, 2007 as discussed below.

 

In July 2007,a new borrowing base notice was received pursuant to our Credit Facilityagreement which reaffirmed our $115.5 million borrowing base but required $1.0million monthly reductions beginning on July 1, 2007 through the nextredetermination date, which was October 1, 2007, at which time a newredetermination would be made.  The October 1,2007 redetermination date was subsequently moved to November 1, 2007pursuant to the fifth amendment to the Credit Facility*.*

 

In August 2007,the fourth amendment to the Credit Facility was executed.  The amendment extended the date for whichother debt outside the Credit Facility must be reduced below $1.0 million from September 3,2007 to October 8, 2007. The October 8, 2007 date was subsequentlymoved to November 1, 2007 pursuant to the fifth amendment to the CreditFacility*.*

 

In October 2007, the fifth amendment to theCredit Facility was executed.  There werefive items addressed in this amendment. First, the borrowing baseredetermination date was adjusted from October 1, 2007 to November 1,2007 for purposes of this one redetermination. Second, the date at which our other debt outside of the Credit Facilitymust be reduced to under $1.0 million was extended from October 8, 2007 toNovember 1, 2007.  Third, the amountof proceeds from an equity infusion that must be applied to the repayment ofborrowings under the Credit Facility was reduced from $100.0 million to $80.0million and the outstanding borrowings under the Credit Facility must bereduced to less that 50% of our then-specified borrowing base after any equityinfusion before making any subsequent distributions.  Fourth, the covenant which prohibited us frommaking distributions if our borrowings exceeded 50% of our borrowing base wasrevised to allow us to make distributions if our borrowings were less than 80%of our borrowing base.  Fifth, theamendment allowed us to borrow under the Credit Facility to make distributionsas long as there has not been a default or event of default under the Creditfacility and any such distributions for any quarter do not exceed EBITDA (asdefined in the Credit Facility) for such quarter.

 

InNovember 2007, a sixth amendment to the Credit Facility was executed whichset our borrowing base under our Credit Facility at $110.5 million pursuant toour semi-annual redetermination,  revisedthe covenant governing borrowing funds to make distributions, and lowered ourborrowing rates. The covenant whichprohibited us from making distributions if our borrowings exceeded 80% of ourborrowing base was revised to allow us to make distributions if our borrowingswere less than 90% of our borrowing base. In addition, the applicablemargins on our borrowing base utilization grid were lowered as referencedabove.

 

OurCredit Facility was amended and restated in February 2008 and additionalborrowings were made pursuant to the acquisition of natural gas and oilproperties in the Permian Basin. See *Note 12. Subsequent Events*for further discussion.

 

72

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**Vanguard Natural Resources, LLCand Subsidiaries**

**Notes to Consolidated FinancialStatements**

**December 31, 2007**

** **

**6.    FinancialInstruments and Price Risk Management Activities**

 

The following tablepresents the carrying amounts and estimated fair values of our financialinstruments as of December 31:

 
| ** **                                              | ** ** | **Vanguard**         | ** **   | **Vanguard Predecessor** | ** ** |
|---------------------------------------------------------|------------|----------------------|--------------|-------------------------------|------------|
| ** **                                              | ** ** | **2007**             | ** **   | **2006**                      | ** ** |
| ** **                                              | ** ** | **Carrying  Amount** | ** **   | **Fair  Value**               | ** ** | **Carrying  Amount** | ** ** | **Fair  Value** | ** ** |
| $75 million Senior Secured Revolver | ** ** | $                    |  — |                          | $          |  — |   | $ |  63,067,500 |   | $ |  63,067,500 | ** ** |
| TCW Notes                                          | ** ** | $                    |  — |                          | $          |  — |   | $ |  31,000,000 |   | $ |  31,000,000 | ** ** |
| $200 million  Senior Secured Revolver                   |       | $                    | 37,400,000   |                          | $          | 37,400,000 |   | $ | — |   | $ | — |   |
| Net liabilities  from price risk management activities  |       | $                    | 556,788      |                          | $          | 556,788 |   | $ | 2,022,079 |   | $ | 2,022,079 |   |

 

At December 31, 2007and 2006, the carrying amounts reported on the consolidated balance sheet forcash and cash equivalents, accounts receivable and accounts payable approximatefair value due to their short-term nature. The estimated fair value offinancial instruments is the amount at which the instrument could be exchangedcurrently between willing parties. We use available marketing data andvaluation methodologies to estimate the fair value of debt. This disclosure ispresented in accordance with SFAS No. 107,*Disclosure about Fair Value of Financial Instruments* and does notimpact our financial position, results of operations or cash flows. The SeniorRevolver credit facilities approximate fair value because these instrument bearinterest at current market rates.

 

From time to time,we enter into natural gas swap agreements with counterparties to hedge pricerisk associated with a portion of our production. These derivatives are notheld for trading purposes. Under these price swaps, we receive a fixed price ona notional quantity of natural gas in exchange for paying a variable pricebased on a market index, such as the Columbia Gas Appalachian Index (“TECOIndex”) natural gas futures.

 

During 2006,natural gas swaps covered 2,673,000 MMBtu, fixing the sales price of thisnatural gas at an average of $6.29 per MMBtu. The derivative contracts enteredinto in 2006 were not specifically designated as hedges under SFAS No. 133*Accounting for Derivative Instruments and HedgingActivities* and therefore did not qualify for hedge accountingtreatment. These derivative contracts are recorded at fair value on theconsolidated balance sheet as short-term and long-term liabilities based upontheir anticipated settlement date. The change in fair value of these derivativecontracts was recorded in the consolidated statement of operations.

 

OnJanuary 3, 2007, the natural gas price swaps referred to above wereterminated which resulted in the Company incurring swap termination fees of$2.8 million. New natural gas swaps and option derivative contracts were put inplace in conjunction with entering into a new credit facility as described in *Note 5. Credit Facilities and Long-Term Debt*. At ourelection, in January 2007 we entered into a NYMEX natural gas collarcontract. A summary of the derivative contracts entered into in January 2007is as follows:

 

**Swap Agreements**

 
| **Contract Period**                 | ** ** | **Volume in MMBtu** | ** ** | **Weighted Average  TECO Index Fixed Price** | ** ** |
|------------------------------------------|------------|-------------------------------|------------|------------------------------------------------------------------|------------|
| July – December 2007 |       | 1,708,357                     |       | $                                                                |  7.50 | ** ** |
| 2008                                     |       | 3,016,134                     |       | $                                                                | 8.14       |   |
| 2009                                     |       | 2,657,046                     |       | $                                                                | 7.87       |   |
| 2010                                     |       | 2,387,640                     |       | $                                                                | 7.53       |   |
| 2011                                     |       | 2,196,012                     |       | $                                                                | 7.15       |   |

 

**Put Option Contracts**

 
| **Contract Period**                 | ** ** | **Volume in MMBtu** | ** ** | **Purchased NYMEX Price Floor** | ** ** |
|------------------------------------------|------------|-------------------------------|------------|------------------------------------------------|------------|
| February –  December 2007 |       | 1,356,480                     |       | $                                              | 7.50       |   |
| 2008                                     |       | 2,211,366                     |       | $                                              | 7.50       |   |
| 2009                                     |       | 1,840,139                     |       | $                                              | 7.50       |   |

 

**Collar Contracts**

 
| **Contract Period**                 | ** ** | **Volume in MMBtu** | ** ** | **NYMEX  Price Floor** | ** ** | **NYMEX  Price Ceiling** | ** ** |
|------------------------------------------|------------|-------------------------------|------------|-----------------------------|------------|-------------------------------|------------|
| February – June 2007 |       | 1,500,000                     |       | $                           |  6.45 |                          | $          |  7.45 |   |
|                                          |            |                               |            |                             |            |                               |            |  |  |

 

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**Vanguard Natural Resources, LLCand Subsidiaries**

**Notes to Consolidated FinancialStatements**

**December 31, 2007**

 

In January 2007,the Company paid $6.5 million for the put option contracts referenced above.Payments for the put option contracts and the swap termination fee were fundedwith borrowings under the Credit Facility.

 

In May 2007, wereset our 2007, 2008 and 2009 natural gas swaps at higher prices as follows:

 
| **Contract Period**                 | ** ** | **Volume in  MMBtu** | ** ** | **Original Weighted Average  TECO Index  Fixed Price** | ** ** | **New Weighted Average  TECO Index  Fixed Price** | ** ** |
|------------------------------------------|------------|---------------------------|------------|----------------------------------------------------------------------------|------------|-----------------------------------------------------------------------|------------|
| July – December 2007 |       | 1,708,357                 |       | $                                                                          |  7.50 |                                                                  | $          |  9.00 | ** ** |
| 2008                                     |       | 3,016,134                 |       | $                                                                          |  8.14 |                                                                  | $          |  9.00 | ** ** |
| 2009                                     |       | 2,657,046                 |       | $                                                                          | 7.87       |                                                                  | $          | 8.85 |   |

 

In connection withresetting our swaps as described above in May 2007, we incurred a $7.3million deferred swap payment obligation with the derivative counterparty whichaccrued interest daily at 7.36% and was payable at the earlier of five daysafter the closing of an equity issuance or November 1, 2007. The deferredswap obligation was paid in October 2007 using proceeds from our IPO.

 

The derivativecontracts entered into in January 2007, and reset in May 2007, werespecifically designated as hedges under SFAS No. 133 *Accountingfor Derivative Instruments and Hedging Activities* and thereforequalify for hedge accounting treatment. These derivative contracts are recordedat fair value on the consolidated balance sheet as short-term and long-termassets and liabilities based upon their anticipated settlement date. The changein fair value of these derivative contracts is recorded in other comprehensiveincome.

 

AtDecember 31, 2007, the Company had open natural gas derivative contractscovering its production as follows:

 

**Swap Agreements**

 
| **Contract Period** | ** ** | **Volume in MMBtu** | ** ** | **Weighted Average  TECO Index Fixed Price** | ** ** |
|--------------------------|------------|-------------------------------|------------|------------------------------------------------------------------|------------|
| 2008                     |       | 3,016,134                     |       | $                                                                |  9.00 | ** ** |
| 2009                     |       | 2,657,046                     |       | $                                                                | 8.85       |   |
| 2010                     |       | 2,387,640                     |       | $                                                                | 7.53       |   |
| 2011                     |       | 2,196,012                     |       | $                                                                | 7.15       |   |

 

**Put Option Contracts**

 
| **Contract Period** | ** ** | **Volume in MMBtu** | ** ** | **Purchased NYMEX Price Floor** | ** ** |
|--------------------------|------------|-------------------------------|------------|------------------------------------------------|------------|
| 2008                     |       | 2,211,366                     |       | $                                              | 7.50       |   |
| 2009                     |       | 1,840,139                     |       | $                                              | 7.50       |   |

 

Inaddition, in December 2007, we entered into an interest rate swapagreement which fixed LIBOR at 3.875% on $20.0 million of borrowings for theperiod from December 2007 to December 2010 to minimize the effect offluctuating interest rates. If LIBOR is lower than the fixed rate in thecontract, we are required to pay the counterparty the difference, andconversely, the counterparty is required to pay us if LIBOR is higher than thefixed interest rate in the contract. We designated the interest rate swap as acash flow hedge under SFAS 133; therefore, the change in fair value of thisinstrument is recorded in other comprehensive income (loss).

 

 In February 2008, in connection with ourrecent acquisition of certain oil and gas properties in the Permian Basin ofWest Texas and Southeastern New Mexico, we assumed fixed-price oil swaps forapproximately 90% of the estimated 2008 through 2011 oil production whicheffectively fixes the sales price on that portion of the production at aweighted average price of $87.29 per barrel. Also, in February 2008, we entered into natural gas collars for2,730,000 MMBtu for gas production in 2008 through 2010, reset the price on2,387,640 MMBtu of natural gas swaps settling in 2010 from $7.53 to $8.76 perMMBtu and entered into a 2012 fixed-price oil swap at $80.00 for 87% of theestimated proved developed producing reserves. In February and March 2008,we entered into additional interest rates swaps on $40.0 million of borrowingswhich settle in January 2008 through 2011. See *Note**12. Subsequent Events*for further discussion.

 

74

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**Vanguard Natural Resources, LLCand Subsidiaries**

**Notes to Consolidated FinancialStatements**

**December 31, 2007**

 

**7.   Asset RetirementObligations**

 

The asset retirementobligations as of December 31 reported on our consolidated balance sheetand the changes in the asset retirement obligations for the year ended December 31,were as follows:

 
| ** **                                                         | ** ** | **Vanguard** | ** ** | **Vanguard  Predecessor** | ** ** |
|--------------------------------------------------------------------|------------|--------------|------------|---------------------------|------------|
| ** **                                                         | ** ** | **2007**     | ** ** | **2006**                  | ** ** |
| Asset retirement obligation at January 1, | ** ** | $            | —     |                      | $          | 212,588 | ** ** |
| Liabilities  added during the current period                       |       | 177,153      |       | 50,496                    |       |
| Accretion  expense                                                 |       | 12,558       |       | 18,307                    |       |
| Revisions to  estimated cash flows                                 |       | —       |       | 137,142                   |       |
| Asset retirement  obligation at December 31,                  |       | $            | 189,711    |                      | $          | 418,533 |   |

 

Accretionexpense for the years ended December 31, 2007, 2006 and 2005 was $12,558,$18,307 and $12,533, respectively.

 

**8.    Related PartyTransactions**

 

AtDecember 31, 2007 and 2006, amounts payable to our largest unitholder werenone and $75,000, respectively. Historically, our Predecessor maintained relationships with severalclosely related companies that directly supported it through administrative andoperational services.  The total cost forservices performed by these affiliates was none and $1.3 million for the yearended December 31, 2007 and 2006, respectively.  Our Predecessor also historically fundedcertain capital requirements of its affiliates. As of December 31, 2006,receivables due from these affiliates were $14.7 million.  These companies are affiliated through commonownership with our largest unitholder.  All of the related party balances at December 31, 2006, wereconveyed to other entities pursuant to the Restructuring and therefore noreceivable balances were outstanding from these affiliates at December 31,2007.  In addition, as of theRestructuring no additional funding of these related parties has occurred.

 

Pursuantto the Restructuring, we rely on Vinland to execute our drilling program,operate our wells and gather our natural gas in Appalachia. We reimburseVinland $60 per well per month (in addition to normal third party operatingcosts) for operating our current natural gas and oil properties in Appalachiaunder a Management Services Agreement (“MSA”) which costs are reflected in ourlease operating expenses.  Also, Vinlandreceives a $0.25 per mcf transportation fee for producing wells as of January 5,2007 and $0.55 per mcf transportation fee on any new wells drilled after January 5,2007 within the area of mutual interest. This transportation fee only encompasses transporting the natural gas tothird party pipelines at which point additional transportation fees to naturalgas markets apply.  These transportationfees are outlined under a Gathering and Compression Agreement (“GCA”) withVinland and are reflected in our lease operating expenses. For the year ended December 31,2007, costs incurred under the MSA were $0.5 million and costs incurred underthe GCA were $1.2 million. In addition, Vinland reimburses us for certain gassales contracts that were fixed at prices below market.  For the year ended December 31, 2007,Vinland’s reimbursement of $1.0 million is reflected in natural gas and oilsales. A net payable of $3.8 million is reflected on our December 31, 2007consolidated balance sheet in connection with these agreements and directexpenses incurred by Vinland related to the drilling of new wells andoperations of all of our existing wells in Appalachia.

 

**9.     Commitmentsand Contingencies**

 

TheCompany is a defendant in a legal proceedings arising in the normal course ofour business. While the outcome and impact of such legal proceedings on theCompany cannot be predicted with certainty, management does not believe that itis probable that the outcome of any action will have a material adverse effecton the Company’s consolidated financial position, results of operations or cashflow.

 

**10.****    Common Units andNet Income per Unit**

 

InApril 2007, the sole member of VNG contributed all of the issued andoutstanding common units in VNG to VNR for six million common unitsrepresenting all of the issued and outstanding common units of VNR at such time.VNR then completed a private equity offering pursuant to which it sold 2.29million common units to certain private investors for $41.2 million. 

 

75

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**Vanguard Natural Resources, LLCand Subsidiaries**

**Notes to Consolidated FinancialStatements**

**December 31, 2007**

 

Theproceeds of this private equity offering were used to make a distribution toMajeed S. Nami, VNR’s largest unitholder. Mr. Nami used a portion of these funds to capitalize Vinland andVinland paid us $3.9 million to reduce outstanding accounts receivable fromVinland. In October 2007, we successfully completed our IPO of 5.25million common units.

 

Basic earnings per unitis computed in accordance with SFAS No. 128,*“Earnings Per Share”* (“SFAS 128”) by dividing netearnings attributable to unitholders by the weighted average number of unitsoutstanding during the period. Diluted earnings per unit is computed byadjusting the average number of units outstanding for the dilutive effect, ifany, of unit equivalents.  The Company uses the treasury stock method todetermine the dilutive effect.  At December 31, 2007, the Company hadtwo classes of units outstanding:  (i) units representing limitedliability company interests (“common units”) listed on NYSE Arca, Inc. underthe symbol VNR and (ii) Class B units, issued to management and anemployee as discussed in *Note 11.Unit-BasedCompensation*.  The Class Bunits participate in distributions and no forfeiture is expected; therefore,all Class B units were considered in the computation of basic earnings perunit.

 

Inaccordance with SFAS 128, dual presentation of basic and diluted earningsper unit has been presented in the consolidated statements of operations forthe year ended December 31, 2007 for each class of units issued andoutstanding at that date, common units and Class B units.  Net incomeper unit was allocated to the units and the Class B units on an equalbasis. No calculation was made for the Vanguard Predecessor period.

 

**11.****   Unit****-Based Compensation**

 

InApril 2007, the sole member reserved 460,000 restricted Class B unitsin VNR for issuance to employees of VNRH. Certain members of management were granted 365,000 restricted Class Bunits in VNR in April 2007, which vest two years from the date of grant.In addition, another 55,000 restricted VNR Class B units were issued in August 2007to two other employees that were hired in April and May, 2007, which willvest over three years.  The remaining 40,000restricted Class B units will be awarded to new employees or members ofour board of directors as they are retained. In October 2007, a board member was granted 5,000 common unitswhich vest over one year. These common units and Class B units were grantedas partial consideration for services to be performed under employmentcontracts and thus will be subject to accounting for these grants under SFAS No. 123(R),*Share-Based Payment.*

 

Thefair value of restricted units issued is determined based on the fair marketvalue of VNR units on the date of the grant. This value is amortized over the vesting period as referencedabove.  A summary of the status of thenon-vested units as of December 31, 2007 is presented below:

 
| ** **                                                     | ** ** | **Number of  Non-vested Units** | ** ** | **Weighted Average  Grant Date  Fair Value** | ** ** |
|----------------------------------------------------------------|------------|-------------------------------------------|------------|-------------------------------------------------------------|------------|
| ** **                                                     | ** ** | ** **                                | ** ** | ** **                                                  | ** ** |
| Non-vested units at December 31, 2006 |       | —                                    |       | $                                                           | —     | ** ** |
| Granted                                                        |       | 425,000                                   |       | 18.14                                                       | ** ** |
| Non-vested units  at December 31, 2007                    |       | 425,000                                   |       | $                                                           | 18.14      |   |

 

AtDecember 31, 2007, there was approximately $5.6 million of unrecognizedcompensation cost related to non-vested restricted units.  The cost is expected to be recognized over anaverage period of approximately 1.8 years. Our consolidated statement ofoperations reflects non-cash compensation of $2.1 million in the selling,general and administrative line item for the year ended December 31, 2007.

 

**12.****    Subsequent Events**

 

In January 2008, we completed the acquisitionof certain oil and gas properties in the Permian Basin of West Texas andSoutheastern New Mexico for an adjusted purchase price of $73.4 million,subject to customary post-closing adjustments. The effective date of the acquisition was October 1, 2007. Thepurchase price includes a payment of $7.8 million paid by us to the seller in December 2007.At December 31, 2007, this amount is reported in non-current deposits inour consolidated balance sheet. In this acquisition, based on internal reserveforecasts, we acquired approximately 4.4 million barrels of oil equivalent, 83%of which are oil and 90% are proved developed producing.The current net production attributable to this purchase is estimated to beapproximately 800 barrels of oil equivalent per day and thereserves-to-production ratio is 15 years.

 

76

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**Vanguard Natural Resources, LLCand Subsidiaries**

**Notes to Consolidated FinancialStatements**

**December 31, 2007**

 

As part of this acquisition, in February 2008,we have assumed fixed-price oil swaps covering approximately 90% of theestimated proved developed producing oil reserves through 2011 at a weightedaverage price of $87.29. This acquisition was funded with borrowings under ourexisting Credit Facility and after consideration of this acquisition and otherborrowings, indebtedness under the Credit Facility totaled $103.0 million. Inconjunction with these new borrowings, in February and March 2008, weentered into interest rate swaps which effectively fix the LIBOR rate at 2.66%to 3.00% on $40.0 million of borrowings. Also, in February 2008, weentered into natural gas collars for 2,730,000 MMBtu for gas production in 2008through 2010, reset the price on 2,387,640 MMBtu of natural gas swaps settlingin 2010 from $7.53 to $8.76 per MMBtu and entered into a 2012 fixed-price oilswap at $80.00 for 87% of the estimated proved developed producing reserves.

 

The following summarizes information concerning ournet positions in open commodity derivatives entered into subsequent to December 31,2007.  The settlement prices of commodityderivatives are based on NYMEX futures prices for collars and put options andare based on the TECO Index for swaps.

 

**Collars**

 
| ** **                                   | ** ** | **Gas**            | ** ** |
|----------------------------------------------|------------|--------------------|------------|
| ** **                                   | ** ** | **MMBtu (a)** | ** ** | **Floor** | ** ** | **Ceiling** | ** ** |
| Production  Period:                          |       |               |       |   |   |   |   |
| March –  September 2008       |       | 700,000            |       | $ | 7.50 |   | $ | 9.00 |   |
| October –  December 2008      |       | 300,000            |       | $ | 7.50 |   | $ | 9.25 |   |
| January 2009  – December 2009 |       | 1,000,000          |       | $ | 7.50 |   | $ | 9.00 |   |
| January 2010  – December 2010 |       | 730,000            |       | $ | 8.00 |   | $ | 9.30 |   |

 

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(a)   OneMMBtu equals one Mcf at a Btu factor of 1,000.

 

**Swaps**

 
| ** **          | ** ** | **Oil**  | ** ** |
|---------------------|------------|----------|------------|
| ** **          | ** ** | **Bbls** | ** ** | **Price** | ** ** |
| Production  Period: |       |     |       |   |   |
| 2008                |       | 182,500  |       | $ | 90.30 |   |
| 2009                |       | 181,500  |       | $ | 87.23 |   |
| 2010                |       | 164,250  |       | $ | 85.65 |   |
| 2011                |       | 151,250  |       | $ | 85.50 |   |
| 2012                |       | 144,000  |       | $ | 80.00 |   |

 

**InterestRates**

 

The following summarizes information concerning ourpositions in open interest rate swaps entered into subsequent to December 31,2007.

 
| ** **                                       | ** ** | **Principal** | ** ** | **Fixed  Libor** | ** ** |
|--------------------------------------------------|------------|---------------|------------|------------------|------------|
| ** **                                       | ** ** | **Balance**   | ** ** | **Rates**        | ** ** |
| Period:                                          | ** ** | ** **    | ** ** | ** **       | ** ** |
| January 31,  2008 to January 31, 2011  |       | $             | 30,000,000 |             | 3.00       | % |
| March 31,  2008 through March 31, 2011 |       | $             | 10,000,000 |             | 2.66       | % |

 

Wedesignated all of the derivatives shown in the preceding tables as cash flowhedges under SFAS 133; therefore, all changes in the fair value of thesecontracts prior to maturity are not shown on the statement of operations butrather are shown in other comprehensive income (loss).  Any realized gains or losses includingpremiums paid for the derivative will be reflected as realized gains (losses)on derivative contracts in the consolidated statement of operations at the timeof maturity.

 

Our Credit Facility wasamended and restated in February 2008 to extend the maturity date from January 3,2011 to March 31, 2011, increase the facility amount from $200.0 millionto $400.0 million, increase our borrowing base from $110.5 million to $150.0million and add two financial institutions.

 

77

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**Supplemental Selected QuarterlyFinancial Information (Unaudited)**

 

Financial information byquarter is summarized below.

 
| ** **                                           | ** ** | **Quarters Ended**                      | ** ** |
|------------------------------------------------------|------------|----------------------------------------------|------------|
| ** **                                           | ** ** | **March 31**                            | ** ** | **June 30** | ** ** | **September 30** | ** ** | **December 31** | ** ** | **Total** |   |
|                                                 |       | **(in  thousands, except per unit amounts)** |       |
| **2007**                                             |       |                                         |       |   |   |   |   |   |   |   |   |
| Natural gas and  oil sales                           |       | $                                            | 8,962      |   | $ | 10,107 |   | $ | 7,641 |   | $ | 7,831 |   | $ | 34,541 |   |
| Realized gain  (losses) on derivative contracts      |       | (748                                         | )          | (918 | ) | 940 |   | 24 |   | (702 | ) |
| Total Revenues                                       |       | 8,214                                        |       | 9,189 |   | 8,581 |   | 7,855 |   | 33,839 |   |
| Total costs and  expenses (1)                        |       | 5,128                                        |       | 4,767 |   | 5,026 |   | 5,694 |   | 20,615 |   |
| Net income  (loss)                                   |       | $                                            | (1,626     | ) | $ | 2,240 |   | $ | 1,051 |   | $ | 984 |   | $ | 2,649 |   |
|                                                 |       |                                         |       |   |   |   |   |   |   |   |   |
| Net income  (loss) per unit:                         |       |                                         |       |   |   |   |   |   |   |   |   |
| Common &  Class B units – basic   |       | $                                            | (0.29      | ) | $ | 0.38 |   | $ | 0.18 |   | $ | 0.09 |   | $ | 0.24 |   |
| Common &  Class B units – diluted |       | $                                            | (0.29      | ) | $ | 0.38 |   | $ | 0.18 |   | $ | 0.09 |   | $ | 0.24 |   |
|                                                 |       |                                         |       |   |   |   |   |   |   |   |   |
| **2006****(2)**                                      |       |                                         |       |   |   |   |   |   |   |   |   |
| Natural gas and  oil sales                           |       | $                                            | 11,163     |   | $ | 8,253 |   | $ | 9,574 |   | $ | 9,859 |   | $ | 38,849 |   |
| Realized gain  (losses) on derivative contracts      |       | (2,020                                       | )          | (322 | ) | (161 | ) | 295 |   | (2,208 | ) |
| Change in fair  value of derivative contracts        |       | 8,814                                        |       | 2,610 |   | 4,428 |   | 1,896 |   | 17,748 |   |
| Total Revenues                                       |       | 17,957                                       |       | 10,541 |   | 13,841 |   | 12,050 |   | 54,389 |   |
| Total costs and  expenses (1)                        |       | 4,452                                        |       | 3,580 |   | 4,162 |   | 8,308 |   | 20,502 |   |
| Net income  (loss)                                   |       | $                                            | 11,702     |   | $ | 4,998 |   | $ | 7,666 |   | $ | 2,189 |   | $ | 26,555 |   |

 

----

(1)   Includes leaseoperating expenses, depreciation, depletion and amortization, selling, generaland administration expenses, bad debt expense and taxes other than income.

(2)   Amounts for 2006are for Vanguard Predecessor. No per unit calculations were made for thisperiod.

 

78

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**Supplemental Natural Gas and OilInformation (Unaudited)**

 

We are a publicly tradedlimited liability company focused on the development and exploitation ofmature, long-lived natural gas and oil properties in the United States.

 

Capitalized costs relatedto natural gas and oil producing activities and related accumulated depletionwere as follows at December 31:

 
| ** **                                                                        | ** ** | **Vanguard** | ** **  | **Vanguard  Predecessor** | ** ** |
|-----------------------------------------------------------------------------------|------------|--------------|-------------|---------------------------|------------|
| ** **                                                                        | ** ** | **2007**     | ** **  | **2006**                  | ** ** |
| Aggregate  capitalized costs relating to natural gas and oil producing activities |       | $            | 135,435,240 |                      | $          | 128,811,908 |   |
| Aggregate  accumulated depletion                                                  |       | (28,451,891  | )           | (24,128,298               | )          |
| Net capitalized  costs                                                            |       | $            | 106,983,349 |                      | $          | 104,683,610 |   |
| FAS 143 asset  retirement obligations                                             |       | $            | 189,711     |                      | $          | 418,533 |   |

 

Costs incurred in naturalgas and oil producing activities, whether capitalized or expensed, were asfollows for the years ended December 31:

 
| ** **                           | ** ** | **Vanguard** | ** **      | **Vanguard  Predecessor** | ** ** |
|--------------------------------------|------------|--------------|-----------------|---------------------------|------------|
| ** **                           | ** ** | **2007**     | ** **      | **2006**                  | ** ** | **2005** | ** ** |
| Property acquisition costs | ** ** | $            |  3,670,561 | ** **                | **$**      | **—** | ** ** | **$** | **—** | ** ** |
| Development  costs                   |       | 12,859,838   |            | 37,467,066                |       | 37,023,753 |   |
| Total cost  incurred                 |       | $            | 16,530,399      |                      | $          | 37,467,066 |   | $ | 37,023,753 |   |

 

The table above includescapitalized internal costs incurred in connection with the development ofnatural gas and oil reserves of $3,880,000 and $1,071,584 in 2006 and 2005,respectively. No internal costs were capitalized in 2007. Additionally,capitalized interest of $75,672, $117,097 and $1,170,240 for the years ended December 31,2007, 2006 and 2005, respectively, are included in the table above.

 

In our December 31,2007 reserve report, the amounts estimated to be spent in 2008, 2009 and 2010to develop our proved undeveloped reserves are $13.5 million, $13.8 million and$8.5 million, respectively.

 

Net quantities of proveddeveloped and undeveloped reserves of natural gas and oil and changes in thesereserves at December 31, 2007, 2006 and 2005 are presented below.Information in these tables is based on reserve reports prepared by ourindependent petroleum engineers, Netherland, Sewell & Associates, Inc. for2007 and 2006 and Schlumberger Data & Consulting Services for 2005.

 
| ** **                         | ** ** | **Gas (in Mcf)** | ** ** | **Oil (in Bbls)** | ** ** |
|------------------------------------|------------|----------------------------|------------|-----------------------------|------------|
| Net proved  reserves               |       |                       |       |                        |       |
| January 1,  2005              |       | 73,564,492                 |       | 38,900                      |       |
| Revisions of  previous estimates   |       | 31,072,849                 |       | 431,344                     |       |
| Extensions,  discoveries and other |       | 6,842,125                  |       | 10,937                      |       |
| Production                         |       | (3,789,185                 | )          | (17,488                     | )          |
| December 31,  2005            |       | 107,690,281                |       | 463,693                     |       |
| Revisions of  previous estimates   |       | (17,529,333                | )          | (106,630                    | )          |
| Extensions,  discoveries and other |       | 8,205,425                  |       | 18,623                      |       |
| Production                         |       | (4,181,708                 | )          | (32,718                     | )          |
| December 31,  2006            |       | 94,184,665                 |       | 342,968                     |       |
| Revisions of  previous estimates   |       | (31,943,375                | )          | 798                         |       |
| Extensions,  discoveries and other |       | 4,544,443                  |       | 16,725                      |       |
| Purchases of  reserves in place    |       | 2,387,113                  |       | 6,165                       |       |
| Production                         |       | (4,044,380                 | )          | (30,629                     | )          |
| December 31,  2007            |       | 65,128,466                 |       | 336,027                     |       |
|                               |       |                       |       |                        |       |
| Proved developed  reserves         |       |                       |       |                        |       |
| December 31,  2005            |       | 53,900,263                 |       | 246,595                     |       |
| December 31,  2006            |       | 48,166,327                 |       | 249,329                     |       |
| December 31,  2007            |       | 48,897,929                 |       | 233,507                     |       |

 

79

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There are numerousuncertainties inherent in estimating quantities of proved reserves, projectingfuture rates of production and projecting the timing of developmentexpenditures, including many factors beyond our control. The reserve datarepresents only estimates. Reservoir engineering is a subjective process ofestimating underground accumulations of natural gas and oil that cannot bemeasured in an exact manner. The accuracy of any reserve estimate is a functionof the quality of available data and of engineering and geologicalinterpretations and judgment. All estimates of proved reserves are determinedaccording to the rules prescribed by the SEC. These rules indicatethat the standard of “reasonable certainty” be applied to proved reserveestimates. This concept of reasonable certainty implies that as more technicaldata becomes available, a positive, or upward, revision is more likely than anegative, or downward, revision. Estimates are subject to revision based upon anumber of factors, including reservoir performance, prices, economic conditionsand government restrictions. In addition, results of drilling, testing andproduction subsequent to the date of an estimate may justify revision of thatestimate. Reserve estimates are often different from the quantities of naturalgas and oil that are ultimately recovered. The meaningfulness of reserveestimates is highly dependent on the accuracy of the assumptions on which theywere based. In general, the volume of production from natural gas and oilproperties we own declines as reserves are depleted. Except to the extent weconduct successful development activities or acquire additional propertiescontaining proved reserves, or both, our proved reserves will decline asreserves are produced. There have been no major discoveries or other events,favorable or adverse, that may be considered to have caused a significantchange in the estimated proved reserves since December 31, 2007, exceptfor the increased reserves associated with the Permian Basin acquisition whichare not reflected below due to the acquisition being completed subsequent toDecember 31, 2007.

 

Results of operationsfrom producing activities were as follows for the years ended December 31:

 
| ** **                                       | ** ** | **Vanguard** | ** **       | **Vanguard  Predecessor** | ** ** |
|--------------------------------------------------|------------|--------------|------------------|---------------------------|------------|
| ** **                                       | ** ** | **2007**     | ** **       | **2006**                  | ** ** | **2005** | ** ** |
| Production revenues(1)                      |       | $            |  33,838,191 |                      | $          |  35,976,571 |   | $ |  30,275,108 |   |
| Production costs(2)                              |       | (7,119,834   | )                | (6,670,542                | )          | (5,856,144 | ) |
| Depreciation,  depletion and amortization        |       | (8,960,524   | )                | (8,511,390                | )          | (6,075,293 | ) |
| Results of  operations from producing activities |       | $            | 17,757,833       |                      | $          | 20,794,639 |   | $ | 18,343,671 |   |

 

----

(1)   Production revenues include realizedlosses on derivative contracts.

(2)   Production cost includes leaseoperating expenses and production related taxes, including ad valorem andseverance taxes.

 

The standardized measureof discounted future net cash flows relating to our proved natural gas and oilreserves at December 31 is as follows (in thousands):

 
| ** **                                                | ** ** | **Vanguard** | ** **    | **Vanguard  Predecessor** | ** ** |
|-----------------------------------------------------------|------------|--------------|---------------|---------------------------|------------|
| ** **                                                | ** ** | **2007**     | ** **    | **2006**                  | ** ** | **2005** | ** ** |
| Future cash inflows                             |       | $            |  587,639 |                      | $          |  663,604 |   | $ |  1,337,090 |   |
| Future  production costs                                  |       | (173,485     | )             | (192,520                  | )          | (138,912 | ) |
| Future development  costs                                 |       | (36,842      | )             | (66,906                   | )          | (76,945 | ) |
| Future net cash  flows                                    |       | 377,312      |          | 404,178                   |       | 1,121,233 |   |
| 10% annual  discount for estimated timing of cash flows   |       | (226,315     | )             | (255,357                  | )          | (720,804 | ) |
| Standardized  measure of discounted future net cash flows |       | $            | 150,997       |                      | $          | 148,821 |   | $ | 400,429 |   |

 

For the December 31,2007 calculations in the preceding table, estimated future cash inflows fromestimated future production of proved reserves were computed using year-endprices of $6.79 per MMBtu for natural gas, adjusted by field for energycontent, and $92.50 per barrel of oil, adjusted for quality, transportationfees and a regional price differential. We may receive amounts different thanthe standardized measure of discounted cash flow for a number of reasons, includingprice changes and the effects of our hedging activities.

 

The following are theprincipal sources of change in our standardized measure of discounted futurenet cash flows (in thousands):

 

80

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| ** **                                                         | ** ** | **Year Ended December 31,(1)** | ** ** |
|--------------------------------------------------------------------|------------|-----------------------------------------------|------------|
| ** **                                                         | ** ** | **Vanguard**                                  | ** ** | **Vanguard  Predecessor** | ** ** |
| ** **                                                         | ** ** | **2007**                                      | ** ** | **2006** | ** ** | **2005** | ** ** |
| Sales and  transfers, net of production costs                      |       | $                                             | (26,718    | ) | $ | (29,306 | ) | $ | (24,419 | ) |
| Net changes in  prices and production costs                        |       | 52,625                                        |       | (231,630 | ) | 125,520 |   |
| Extensions  discoveries and improved recovery, less related costs  |       | 10,791                                        |       | 21,110 |   | 20,027 |   |
| Changes in  estimated future development costs                     |       | 18,045                                        |       | (24,336 | ) | (58,972 | ) |
| Previously  estimated development costs incurred during the period |       | 16,531                                        |       | 37,467 |   | 37,024 |   |
| Revision of  previous quantity estimates                           |       | (75,071                                       | )          | (31,726 | ) | 144,471 |   |
| Accretion of  discount                                             |       | 14,882                                        |       | 40,043 |   | 17,305 |   |
| Purchases of  reserves in place                                    |       | 4,249                                         |       | — |   | — |   |
| Change in  production rates, timing and other                      |       | (13,158                                       | )          | (33,230 | ) | (33,574 | ) |
| Net change                                                         |       | $                                             | 2,176      |   | $ | (251,608 | ) | $ | 227,382 |   |

 

----

(1)          This disclosurereflects changes in the standardized measure calculation excluding the effectsof hedging activities.

 

81

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**SCHEDULE II**

 

**VANGUARDNATURAL RESOURCES, LLC**

**VALUATIONAND QUALIFYING ACCOUNTS**

 

**YearEnded December 31, 2007**

 
| **Description**                  | ** ** | **Balance at  Beginning  of Period** | ** ** | **Charged to  Costs and  Expenses** | ** ** | **Deductions** | ** ** | **Charged  to Other  Accounts** | ** ** | **Balance at  End of  Period** | ** ** |
|----------------------------------|------------|------------------------------------------------|------------|-----------------------------------------------|------------|----------------|------------|--------------------------------------|------------|------------------------------------------|------------|
| Allowance for  doubtful accounts |       | $                                              | —     |                                          | $          | 1,007,461      |       | $                                    | —     |                                     | $          | — |   | $ | 1,007,461 |   |
|                                  |            |                                                |            |                                               |            |                |            |                                      |            |                                          |            |  |  |  |  |  |

 

There was no allowance for doubtful accountsat December 31, 2005 or 2006.

 

82

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| **ITEM 9.** | **CHANGES  IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE** |
|------------------|-------------------------------------------------------------------------------------------|

 

None.

 
| **ITEM 9A.** | **CONTROLS  AND PROCEDURES** |
|-------------------|------------------------------|

 

**Evaluationof Disclosure Controls and Procedures**

 

Based on their evaluationas of the end of the fiscal year ended December 31, 2007, our principalexecutive officer and principal financial officer have concluded that ourdisclosure controls and procedures (as defined in Rules 13a-15(e) and15d-15(e) under the Exchange Act) are effective to ensure that informationrequired to be disclosed in reports that we file or submit under the ExchangeAct are recorded, processed, summarized and reported within the time periodsspecified in the SEC’s rules and forms.

 

**Changesin Internal Control over Financial Reporting**

 

There have been nochanges in our internal control over financial reporting that occurred duringthe most recent fiscal quarter that have materially affected, or are reasonablylikely to materially affect, our internal control over financial reporting.

 

**Management’sReport on Internal Control Over Financial Reporting**

 

This annual report doesnot include a report of management’s assessment regarding internal control overfinancial reporting or an attestation report of the company’s registered publicaccounting firm due to a transition period established by rules of the SECfor newly public companies.

 
| **ITEM 9B.** | **OTHER  INFORMATION** |
|-------------------|------------------------|

 

None.

 

83

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**PART III**

 
| **ITEM 10.** | **DIRECTORS,  EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE** |
|-------------------|-------------------------------------------------------------|

 

Item 10 will beincorporated by reference pursuant to Regulation 14A under the SecuritiesExchange Act of 1934.  The Registrantexpects to file a definitive proxy statement with the Securities and ExchangeCommission within 120 days after the close of the year ended December 31,2007.

 
| **ITEM 11.** | **EXECUTIVE  COMPENSATION** |
|-------------------|-----------------------------|

 

Item 11 will beincorporated by reference pursuant to Regulation 14A under the SecuritiesExchange Act of 1934.  The Registrantexpects to file a definitive proxy statement with the Securities and ExchangeCommission within 120 days after the close of the year ended December 31,2007.

 
| **ITEM 12.** | **SECURITY  OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER  MATTERS** |
|-------------------|------------------------------------------------------------------------------------------------------|

 

Item 12 will beincorporated by reference pursuant to Regulation 14A under the SecuritiesExchange Act of 1934.  The Registrantexpects to file a definitive proxy statement with the Securities and ExchangeCommission within 120 days after the close of the year ended December 31,2007.

 
| **ITEM 13.** | **CERTAIN  RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE** |
|-------------------|--------------------------------------------------------------------------------|

 

Item 13 will beincorporated by reference pursuant to Regulation 14A under the SecuritiesExchange Act of 1934.  The Registrantexpects to file a definitive proxy statement with the Securities and ExchangeCommission within 120 days after the close of the year ended December 31,2007.

 
| **ITEM 14.** | **PRINCIPAL  ACCOUNTANT FEES AND SERVICES** |
|-------------------|---------------------------------------------|

 

Item 14 will beincorporated by reference pursuant to Regulation 14A under the SecuritiesExchange Act of 1934.  The Registrantexpects to file a definitive proxy statement with the Securities and ExchangeCommission within 120 days after the close of the year ended December 31,2007.

 

84

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**PART IV**

 

**ITEM 15.  EXHIBITS AND FINANCIALSTATEMENT SCHEDULES**

 

**(a)  Thefollowing documents are filed as a part of this report:**

 

Financialstatements

 

The followingconsolidated financial statements are included in Part II, Item 8 ofthis report:

 
|                                                                                  |     |
|---------------------------------------------------------------------------------------|----------|
| ** **                                                                            | **Page** |
|                                                                                  |     |
| Reports of Independent Registered Public Accounting  Firms                            | 57       |
| Consolidated  Balance Sheet                                                           | 60       |
| Consolidated Statement of Operations                                                  | 61       |
| Consolidated Statement of Members’ Equity                                        | 62       |
| Consolidated Statement of Cash Flows                                                  | 63       |
| Consolidated Statement of Comprehensive Income                                        | 64       |
| Notes to Consolidated Financial Statements                                            | 65       |
| Financial statement  schedules and supplementary information required to be submitted |     |
| Schedule II —  Valuation and Qualifying Accounts                       | 82       |

 

**(b)     Exhibits**

 

The following exhibitsare incorporated by reference into the filing indicated or are filed herewith.

 
| **Exhibit   No.** | ** ** | **Exhibit Title**                                                                                                                                                                                 | ** ** | **Incorporated   by Reference to the Following**                       |
|-------------------|------------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|------------------------------------------------------------------------|
| 3.1               |       | Certificate  of Formation of Vanguard Natural Resources, LLC                                                                                                                                           |       | Form S-1/A,  filed April 25, 2007 (File No. 333-142363) |
| 3.2               |       | Second  Amended and Restated Limited Liability Company Agreement of Vanguard Natural  Resources, LLC (including specimen unit certificate for the units)                                               |       | Form 8-K,  filed November 2, 2007 (File No. 001-33756)  |
| 10.1              |       | Amended  and Restated Credit Agreement, dated February 14, 2008, by and between  Nami Holding Company, LLC, Citibank, N.A., as administrative agent and L/C  issuer and the lenders party thereto |       | Filed  herewith                                                        |
| 10.2              |       | Vanguard  Natural Resources, LLC Long-Term Incentive Plan                                                                                                                                              |       | Form 8-K,  filed October 24, 2007 (File No. 001-33756)  |
| 10.3              |       | Form of  Vanguard Natural Resources, LLC Long-Term Incentive Plan Phantom Options  Grant Agreement                                                                                                |       | Form S-1/A,  filed April 25, 2007 (File No. 333-142363) |
| 10.4              |       | Vanguard  Natural Resources, LLC Class B Unit Plan                                                                                                                                                |       | Form 8-K,  filed October 24, 2007 (File No. 001-33756)  |
| 10.5              |       | Form of  Vanguard Natural Resources, LLC Class B Unit Plan Restricted  Class B Unit Grant                                                                                               |       | Form S-1/A,  filed April 25, 2007 (File No. 333-142363) |
| 10.6              |       | Management  Services Agreement, effective January 5, 2007, by and between Vinland  Energy Operations, LLC, Vanguard Natural Gas, LLC, Trust Energy Company, LLC  and Ariana Energy, LLC           |       | Form S-1/A,  filed April 25, 2007 (File No. 333-142363) |
| 10.7              |       | Participation  Agreement, effective January 5, 2007, by and between Vinland Energy  Eastern, LLC, Vanguard Natural Gas, LLC, Trust Energy Company, LLC and Ariana  Energy, LLC                    |       | Form S-1/A,  filed April 25, 2007 (File No. 333-142363) |
| 10.8              |       | Gathering  and Compression Agreement, effective January 5, 2007, by and between  Vinland Energy Gathering, LLC, Vinland Energy Eastern, LLC, Vanguard Natural  Gas, LLC and Ariana Energy, LLC    |       | Form S-1/A,  filed April 25, 2007 (File No. 333-142363) |
| 10.9              |       | Gathering  and Compression Agreement, effective January 5, 2007, by and between  Vinland Energy Gathering, LLC, Vinland Energy Eastern, LLC, Vanguard Natural  Gas, LLC and Trust Energy Company  |       | Form S-1/A,  filed April 25, 2007 (File No. 333-142363) |
| 10.10             |       | Gathering  and Compression Agreement, effective January 5, 2007, by and between  Vinland Energy Gathering, LLC and Nami Resources Company, L.L.C.                                                 |       | Form S-1/A,  filed April 25, 2007 (File No. 333-142363) |
| 10.11             |       | Well  Services Agreement, effective January 5, 2007, by and between Vinland  Energy Operations, LLC, Vanguard Natural Gas, LLC and Ariana Energy, LLC                                             |       | Form S-1/A,  filed April 25, 2007 (File No. 333-142363) |

 

85

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| 10.12 |   | Well  Services Agreement, effective January 5, 2007, by and between Vinland  Energy Operations, LLC, Vanguard Natural Gas, LLC and Trust Energy Company,  LLC                                                                               |   | Form S-1/A,  filed April 25, 2007 (File No. 333-142363)     |
|-------|--------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|--------|----------------------------------------------------------------------------|
| 10.13 |   | Well  Services Agreement, effective January 5, 2007, by and between Vinland  Energy Operations, LLC and Nami Resources Company, L.L.C.                                                                                                      |   | Form S-1/A,  filed April 25, 2007 (File No. 333-142363)     |
| 10.14 |   | Amended  and Restated Operating Agreement by and between Vinland Energy Operations,  LLC, Vinland Energy Eastern, LLC and Ariana Energy, LLC, dated  October 2, 2007 and effective as of January 5, 2007                               |   | Form S-1/A,  filed October 22, 2007 (File No. 333-142363)   |
| 10.15 |   | Operating  Agreement, effective January 5, 2007, by and between Vinland Energy  Operations, LLC, Vinland Energy Eastern, LLC and Trust Energy Company, LLC                                                                                  |   | Form S-1/A,  filed April 25, 2007 (File No. 333-142363)     |
| 10.16 |   | Amended  and Restated Indemnity Agreement by and between Nami Resources Company,  L.L.C., Vinland Energy Eastern, LLC, Trust Energy Company, LLC, Vanguard  Natural Gas, LLC and Vanguard Natural Resources, LLC, dated  September 11, 2007 |   | Form S-1/A,  filed September 18, 2007 (File No. 333-142363) |
| 10.17 |   | Revenue  Payment Agreement by and between Nami Resources Company, L.L.C. and Trust  Energy Company, dated April 18, 2007 and effective as of January 5,  2007                                                                          |   | Form S-1/A,  filed August 21, 2007 (File No. 333-142363)    |
| 10.18 |   | Gas  Supply Agreement, dated April 18, 2007, by and between Nami Resources  Company, L.L.C. and Trust Energy Company                                                                                                                        |   | Form S-1/A,  filed April 25, 2007 (File No. 333-142363)     |
| 10.19 |   | Amended  Employment Agreement, dated April 18, 2007, by and between Scott W.  Smith, VNR Holdings, LLC and Vanguard Natural Resources, LLC                                                                                                  |   | Form S-1/A,  filed April 25, 2007 (File No. 333-142363)     |
| 10.20 |   | Amended  Employment Agreement, dated April 18, 2007, by and between Richard A.  Robert, VNR Holdings, LLC and Vanguard Natural Resources, LLC                                                                                               |   | Form S-1/A,  filed April 25, 2007 (File No. 333-142363)     |
| 10.21 |   | Registration Rights Agreement, dated April 18, 2007,between Vanguard Natural Resources, LLC  and the private investors named therein                                                                                                        |   | Form S-1/A,  filed April 25, 2007 (File No. 333-142363)     |
| 10.22 |   | Purchase Agreement, dated April 18, 2007,between Vanguard Natural Resources, LLC,  Majeed S. Nami and the private investors named therein                                                                                                   |   | Form S-1/A,  filed April 25, 2007 (File No. 333-142363)     |
| 10.23 |   | Omnibus  Agreement, dated October 29, 2007, among Majeed S. Nami, Vanguard  Natural Resources, LLC, Vanguard Natural Gas, LLC, Ariana Energy, LLC and  Trust Energy Company, LLC.                                                           |   | Form 8-K,  filed November 2, 2007 (File No. 001-33756)      |
| 10.24 |   | Employment  Agreement, dated May 15, 2007, by and between Britt Pence, VNR Holdings,  LLC and Vanguard Natural Resources, LLC                                                                                                               |   | Form S-1/A,  filed July 5, 2007 (File No. 333-142363)       |
| 10.25 |   | Natural  Gas Contract, dated May 26, 2003, between Nami Resources  Company, Inc. and Osram Sylvania Products, Inc.                                                                                                                |   | Form S-1/A,  filed August 21, 2007 (File No. 333-142363)    |
| 10.26 |   | Natural  Gas Purchase Contract, dated December 16, 2004, between Nami Resources  Company, LLC and Dominion Field Services, Inc.                                                                                                        |   | Form S-1/A,  filed August 21, 2007 (File No. 333-142363)    |
| 10.27 |   | Natural  Gas Purchase Contract, dated December 28, 2004, between Nami Resources  Company, LLC and Dominion Field Services, Inc.                                                                                                        |   | Form S-1/A,  filed August 21, 2007 (File No. 333-142363)    |
| 10.28 |   | Director  Compensation Agreement                                                                                                                                                                                                                 |   | Form S-1/A,  filed September 18, 2007 (File No. 333-142363) |
| 10.29 |   | Purchase  and Sale Agreement, dated December 21, 2007, among Vanguard Permian, LLC  and Apache Corporation                                                                                                                                  |   | Form 8-K/A,  filed February 13, 2008 (File No. 001-33756)   |
| 10.30 |   | Amended  Purchase and Sale Agreement, dated January 31, 2008, among Vanguard  Permian, LLC and Apache Corporation                                                                                                                           |   | Form 8-K/A,  filed February 4, 2008 (File No. 001-33756)    |
| 21.1  |   | List  of subsidiaries of Vanguard Natural Resources, LLC                                                                                                                                                                                         |   | Filed  herewith                                                            |
| 24.1  |   | Powers  of Attorney (contained on the signature page)                                                                                                                                                                                            |   | Filed  herewith                                                            |
| 31.1  |   | Certification  of Chief Executive Officer Pursuant to Rule 13a — 14 of the Securities  and Exchange Act of 1934, as Adopted Pursuant to Section 302 of the  Sarbanes-Oxley Act of 2002                                       |   | Filed  herewith                                                            |
| 31.2  |   | Certification  of Chief Financial Officer Pursuant to Rule 13a — 14 of the  Securities and Exchange Act of 1934, as Adopted Pursuant to Section 302  of the Sarbanes-Oxley Act of 2002                                       |   | Filed  herewith                                                            |
| 32.1  |   | Certification  of Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as  Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002                                                                               |   | Filed  herewith                                                            |
| 32.2  |   | Certification  of Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as  Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002                                                                               |   | Filed  herewith                                                            |

 

86

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**SIGNATURES**

 

Pursuant to therequirements of Section 13 or 15(d) of the Securities Exchange Act of1934, Vanguard Natural Resources, LLC has duly caused this report to be signedon its behalf by the undersigned, thereunto duly authorized on the 31st dayof March, 2008.

 
| VANGUARD  NATURAL RESOURCES, LLC |                                    |   |
|----------------------------------|-----------------------------------------|--------|
|                             | By                                      |   |   | /s/  Scott W.  Smith |
|                             | Scott W. Smith                          |   |   |
|                             | *President and Chief Executive Officer* |   |   |
|                                  |                                         |        |  |  |  |  |

 

KNOW ALL MEN BY THESEPRESENTS, that each person whose signature appears below constitutes andappoints Scott W. Smith and Richard A. Robert, and each of them severally, histrue and lawful attorney or attorneys-in-fact and agents, with full power toact with or without the others and with full power of substitution andresubstitution, to execute in his name, place and stead, in any and allcapacities, any or all amendments to this Annual Report on Form 10-K, withall exhibits thereto, and other documents in connection therewith, with theSecurities and Exchange Commission, granting unto said attorneys-in-fact andagents and each of them, full power and authority to do and perform in the nameof on behalf of the undersigned, in any and all capacities, each and every actand thing necessary or desirable to be done in and about the premises, to allintents and purposes and as fully as they might or could do in person, herebyratifying, approving and confirming all that said attorneys-in-fact and agentsor their substitutes may lawfully do or cause to be done by virtue hereof.

 

Pursuant to therequirements of the Securities Exchange Act of 1934, this report has beensigned below by the following persons on behalf of the registrant and in thecapacities and on the dates indicated.

 

 
| March 31, 2008 | /s/ Scott W. Smith                               |
|---------------------|--------------------------------------------------|
|                | Scott W. Smith                                   |
|                | President, Chief Executive Officer  and Director |
|                | (Principal Executive Officer)                    |
|                |                                             |
|                |                                             |
| March 31, 2008 | /s/ Richard A. Robert                            |
|                | Richard A. Robert                                |
|                | Executive Vice President and Chief               |
|                | Financial Officer (Principal  Financial Officer) |
|                |                                             |
|                |                                             |
| March 31, 2008 | /s/ W. Richard Anderson                          |
|                | W. Richard Anderson                              |
|                | Director                                         |
|                |                                             |
|                |                                             |
| March 31, 2008 | /s/ Thomas M. Blake                              |
|                | Thomas M. Blake                                  |
|                | Director                                         |
|                |                                             |
|                |                                             |
| March 31, 2008 | /s/ Bruce W. McCullough                          |
|                | Bruce W. McCullough                              |
|                | Director                                         |
|                |                                             |
|                |                                             |
| March 31, 2008 | /s/ John R. McGoldrick                           |
|                | John R. McGoldrick                               |
|                | Director                                         |
|                |                                             |
|                |                                             |
| March 31, 2008 | /s/ Loren Singletary                             |
|                | Loren Singletary                                 |
|                | Director                                         |
|                |                                             |
|                |                                             |
| March 31, 2008 | /s/ Lasse Wagene                                 |
|                | Lasse Wagene                                     |
|                | Director                                         |

 

87

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**VanguardNatural Resources, LLC**

**EXHIBITINDEX**

 

Each exhibit identifiedbelow is filed as a part of this Report.

 
| **Exhibit  No.** | ** ** | **Exhibit Title**                                                                                                                                                                                                                          | ** ** | **Incorporated  by Reference to the Following**                            |
|------------------|------------|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|----------------------------------------------------------------------------|
| 3.1              |       | Certificate of  Formation of Vanguard Natural Resources, LLC                                                                                                                                                                                    |       | Form S-1/A, filed  April 25, 2007 (File No. 333-142363)     |
| 3.2              |       | Second Amended and  Restated Limited Liability Company Agreement of Vanguard Natural Resources,  LLC (including specimen unit certificate for the units)                                                                                        |       | Form 8-K, filed  November 2, 2007 (File No. 001-33756)      |
| 10.1             |       | Amended and Restated  Credit Agreement, dated February 14, 2008, by and between Nami Holding  Company, LLC, Citibank, N.A., as administrative agent and L/C issuer and the  lenders party thereto                                          |       | Filed herewith                                                             |
| 10.2             |       | Vanguard Natural  Resources, LLC Long-Term Incentive Plan                                                                                                                                                                                       |       | Form 8-K, filed  October 24, 2007 (File No. 001-33756)      |
| 10.3             |       | Form of Vanguard  Natural Resources, LLC Long-Term Incentive Plan Phantom Options Grant  Agreement                                                                                                                                         |       | Form S-1/A, filed  April 25, 2007 (File No. 333-142363)     |
| 10.4             |       | Vanguard Natural  Resources, LLC Class B Unit Plan                                                                                                                                                                                         |       | Form 8-K, filed  October 24, 2007 (File No. 001-33756)      |
| 10.5             |       | Form of Vanguard  Natural Resources, LLC Class B Unit Plan Restricted Class B Unit  Grant                                                                                                                                        |       | Form S-1/A, filed  April 25, 2007 (File No. 333-142363)     |
| 10.6             |       | Management Services  Agreement, effective January 5, 2007, by and between Vinland Energy  Operations, LLC, Vanguard Natural Gas, LLC, Trust Energy Company, LLC and  Ariana Energy, LLC                                                    |       | Form S-1/A, filed  April 25, 2007 (File No. 333-142363)     |
| 10.7             |       | Participation  Agreement, effective January 5, 2007, by and between Vinland Energy  Eastern, LLC, Vanguard Natural Gas, LLC, Trust Energy Company, LLC and Ariana  Energy, LLC                                                             |       | Form S-1/A, filed  April 25, 2007 (File No. 333-142363)     |
| 10.8             |       | Gathering and  Compression Agreement, effective January 5, 2007, by and between Vinland  Energy Gathering, LLC, Vinland Energy Eastern, LLC, Vanguard Natural Gas, LLC  and Ariana Energy, LLC                                             |       | Form S-1/A, filed  April 25, 2007 (File No. 333-142363)     |
| 10.9             |       | Gathering and  Compression Agreement, effective January 5, 2007, by and between Vinland  Energy Gathering, LLC, Vinland Energy Eastern, LLC, Vanguard Natural Gas, LLC  and Trust Energy Company                                           |       | Form S-1/A, filed  April 25, 2007 (File No. 333-142363)     |
| 10.10            |       | Gathering and  Compression Agreement, effective January 5, 2007, by and between Vinland  Energy Gathering, LLC and Nami Resources Company, L.L.C.                                                                                          |       | Form S-1/A, filed  April 25, 2007 (File No. 333-142363)     |
| 10.11            |       | Well Services  Agreement, effective January 5, 2007, by and between Vinland Energy Operations,  LLC, Vanguard Natural Gas, LLC and Ariana Energy, LLC                                                                                      |       | Form S-1/A, filed  April 25, 2007 (File No. 333-142363)     |
| 10.12            |       | Well Services  Agreement, effective January 5, 2007, by and between Vinland Energy  Operations, LLC, Vanguard Natural Gas, LLC and Trust Energy Company, LLC                                                                               |       | Form S-1/A, filed  April 25, 2007 (File No. 333-142363)     |
| 10.13            |       | Well Services  Agreement, effective January 5, 2007, by and between Vinland Energy  Operations, LLC and Nami Resources Company, L.L.C.                                                                                                     |       | Form S-1/A, filed  April 25, 2007 (File No. 333-142363)     |
| 10.14            |       | Amended and Restated  Operating Agreement by and between Vinland Energy Operations, LLC, Vinland  Energy Eastern, LLC and Ariana Energy, LLC, dated October 2, 2007 and  effective as of January 5, 2007                              |       | Form S-1/A, filed  October 22, 2007 (File No. 333-142363)   |
| 10.15            |       | Operating Agreement,  effective January 5, 2007, by and between Vinland Energy Operations,  LLC, Vinland Energy Eastern, LLC and Trust Energy Company, LLC                                                                                 |       | Form S-1/A, filed  April 25, 2007 (File No. 333-142363)     |
| 10.16            |       | Amended and Restated  Indemnity Agreement by and between Nami Resources Company, L.L.C., Vinland  Energy Eastern, LLC, Trust Energy Company, LLC, Vanguard Natural Gas, LLC and  Vanguard Natural Resources, LLC, dated September 11, 2007 |       | Form S-1/A, filed  September 18, 2007 (File No. 333-142363) |
| 10.17            |       | Revenue Payment  Agreement by and between Nami Resources Company, L.L.C. and Trust Energy  Company, dated April 18, 2007 and effective as of January 5, 2007                                                                          |       | Form S-1/A, filed  August 21, 2007 (File No. 333-142363)    |
| 10.18            |       | Gas Supply Agreement,  dated April 18, 2007, by and between Nami Resources Company, L.L.C. and  Trust Energy Company                                                                                                                       |       | Form S-1/A, filed  April 25, 2007 (File No. 333-142363)     |
| 10.19            |       | Amended Employment  Agreement, dated April 18, 2007, by and between Scott W. Smith, VNR  Holdings, LLC and Vanguard Natural Resources, LLC                                                                                                 |       | Form S-1/A, filed  April 25, 2007 (File No. 333-142363)     |
| 10.20            |       | Amended Employment  Agreement, dated April 18, 2007, by and between Richard A. Robert, VNR  Holdings, LLC and Vanguard Natural Resources, LLC                                                                                              |       | Form S-1/A, filed  April 25, 2007 (File No. 333-142363)     |
| 10.21            |       | Registration  Rights Agreement, dated April 18, 2007,between  Vanguard Natural Resources, LLC and the private investors named therein                                                                                                      |       | Form S-1/A, filed  April 25, 2007 (File No. 333-142363)     |

 

88

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| 10.22 |   | Purchase Agreement, dated April 18, 2007,between Vanguard Natural Resources, LLC,  Majeed S. Nami and the private investors named therein                                                             |   | Form S-1/A,  filed April 25, 2007 (File No. 333-142363)     |
|-------|--------|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|--------|----------------------------------------------------------------------------|
| 10.23 |   | Omnibus  Agreement, dated October 29, 2007, among Majeed S. Nami, Vanguard  Natural Resources, LLC, Vanguard Natural Gas, LLC, Ariana Energy, LLC and  Trust Energy Company, LLC.                     |   | Form 8-K,  filed November 2, 2007 (File No. 001-33756)      |
| 10.24 |   | Employment  Agreement, dated May 15, 2007, by and between Britt Pence, VNR Holdings,  LLC and Vanguard Natural Resources, LLC                                                                         |   | Form S-1/A,  filed July 5, 2007 (File No. 333-142363)       |
| 10.25 |   | Natural  Gas Contract, dated May 26, 2003, between Nami Resources Company, Inc.  and Osram Sylvania Products, Inc.                                                                          |   | Form S-1/A,  filed August 21, 2007 (File No. 333-142363)    |
| 10.26 |   | Natural  Gas Purchase Contract, dated December 16, 2004, between Nami Resources  Company, LLC and Dominion Field Services, Inc.                                                                  |   | Form S-1/A,  filed August 21, 2007 (File No. 333-142363)    |
| 10.27 |   | Natural  Gas Purchase Contract, dated December 28, 2004, between Nami Resources  Company, LLC and Dominion Field Services, Inc.                                                                  |   | Form S-1/A,  filed August 21, 2007 (File No. 333-142363)    |
| 10.28 |   | Director  Compensation Agreement                                                                                                                                                                           |   | Form S-1/A,  filed September 18, 2007 (File No. 333-142363) |
| 10.29 |   | Purchase  and Sale Agreement, dated December 21, 2007, among Vanguard Permian, LLC  and Apache Corporation                                                                                            |   | Form 8-K/A,  filed February 13, 2008 (File No. 001-33756)   |
| 10.30 |   | Amended  Purchase and Sale Agreement, dated January 31, 2008, among Vanguard  Permian, LLC and Apache Corporation                                                                                     |   | Form 8-K/A,  filed February 4, 2008 (File No. 001-33756)    |
| 21.1  |   | List  of subsidiaries of Vanguard Natural Resources, LLC                                                                                                                                                   |   | Filed  herewith                                                            |
| 24.1  |   | Powers  of Attorney (contained on the signature page)                                                                                                                                                      |   | Filed  herewith                                                            |
| 31.1  |   | Certification  of Chief Executive Officer Pursuant to Rule 13a — 14 of the  Securities and Exchange Act of 1934, as Adopted Pursuant to Section 302  of the Sarbanes-Oxley Act of 2002 |   | Filed  herewith                                                            |
| 31.2  |   | Certification  of Chief Financial Officer Pursuant to Rule 13a — 14 of the  Securities and Exchange Act of 1934, as Adopted Pursuant to Section 302  of the Sarbanes-Oxley Act of 2002 |   | Filed  herewith                                                            |
| 32.1  |   | Certification  of Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as  Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002                                         |   | Filed  herewith                                                            |
| 32.2  |   | Certification  of Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as  Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002                                         |   | Filed  herewith                                                            |

 

89

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