UNITED
STATES


SECURITIES
AND EXCHANGE COMMISSION


Washington, D.C.
20549




Form 10-K


(MarkOne)x
                                
                                ANNUAL
      REPORT PURSUANT TO SECTION 13 OR 15(d) OF
                                  THE
      SECURITIES EXCHANGE ACT OF 1934For
      the fiscal year ended December 31,
2008




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




Commission
File Number 001-33756




Vanguard Natural Resources, LLC


(Exact Name of Registrant as Specified in Its Charter)




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




Telephone
Number: (832) 327-2255


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




Title
      of Each Class
              
              Name
      of Each Exchange
                on
      which RegisteredCommon
      Units
              
              NYSE
      Arca, Inc.




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




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


Yeso
            
            No
      x




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


Yeso
            
            No
      x




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


and
      (2) has been subject to such filing requirements for the past
      90 days.
            
            Yesx
            
            No
      o




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


Part III
      of this Form 10-K or any amendment to this
      Form 10-K.
            
            
            
            o




Indicate
by check mark whether the registrant is a large accelerated filer, an
accelerated filer, a non-accelerated filer, or a smaller reporting company. See
definition of “large accelerated filer,” “accelerated filer” and “smaller
reporting company” in Rule 12b-2 of the Exchange Act.


Large
      accelerated filero
            
            Accelerated
      filerxNon-accelerated
      filero
            
            Smaller
      reporting companyo(Do
      not check if smaller reporting company)




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


Yes o
            
            No x




The
aggregate market value of Vanguard Natural Resources, LLC common units held by
non-affiliates of the registrant as of June 30, 2008 was approximately
$121,851,750 based upon the New York Stock Exchange composite transaction
closing price.




As of
March 5, 2009, 12,145,873 of the registrant’s common units remained
outstanding.




Documents
Incorporated by Reference:


Portions
of the registrant’s proxy statement to be furnished to unitholders  in
connection with its 2009 Annual Meeting of Unitholders are incorporated by
reference in Part III, Items 10-14 of this annual report on Form 10-K
for the year ending December 31, 2008 (“this Annual Report”).




























Vanguard Natural Resources, LLC




TABLE
OF CONTENTS




Caption
            
            PageGlossary of
      TermsPART IItem 1.
            Business
            1Item 1A.
            Risk
      Factors
            14Item 1B.
            Unresolved Staff
      Comments
            29Item 2.
            Properties
            29Item 3.
            Legal
      Proceedings
            30Item 4.
            Submission of Matters to a Vote
      of Security Holders
            30PART IIItem 5.
            Market for Registrant’s Common
      Units, Related Stockholder Matters and Issuer Purchases of
      EquitySecurities
            30Item 6.
            Selected Financial
      Data
            32Item 7.
            Management’s Discussion and
      Analysis of Financial Condition and Results of
      Operations
            37Item 7A.
            Quantitative and Qualitative
      Disclosures About Market Risk
            52Item 8.
            Financial Statements and
      Supplementary Data
            55Item 9.
            Changes in and Disagreements with
      Accountants on Accounting and Financial
    Disclosure
            82Item 9A.
            Controls and
      Procedures
            82Item 9B.
            Other
      Information
            84PART IIIItem 10.
            Directors, Executive Officers
      and Corporate Governance
            84Item 11.
            Executive
      Compensation
            84Item 12.
            Security Ownership of Certain
      Beneficial Owners and Management and Related Stockholder
      Matters
            84Item 13.
            Certain Relationships and
      Related Transactions, and Director Independence
            84Item 14.
            Principal Accountant Fees and
      Services
            85PART IVItem 15.
            Exhibits and Financial Statement
      Schedules
            86Signatures
            89







Table of Contents







Forward
Looking Statements




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




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




·
      the volatility of realized natural gas and oil
  prices;





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





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





·
      our business and financial
strategy;





·
      our drilling locations;





·
      technology;





·
      our cash flow, liquidity and financial
position;





·
      our production volumes;





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





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





·
      our future operating results;





·
      our prospect development and property
  acquisitions;





·
      the marketing of natural gas and
oil;





·
      competition in the natural gas and oil
industry;





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





·
      governmental regulation of the natural gas and oil
    industry;





·
      environmental regulations;





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





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





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








Table of Contents













GLOSSARY OF TERMS




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




/day
              =
      per day
              MBbls
              =
      thousand barrelsBbls
              =
      barrels
              Mcf
              =
      thousand cubic feetBcf
              =
      billion cubic feet
              Mcfe
              =
      thousand cubic feet of natural gas equivalentsBcfe
              =
      billion cubic feet equivalents
              MMBtu
              =
      million British thermal unitsBtu
              =
      British thermal unit
              MMcfe
              =
      million cubic feet of natural gas equivalents




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





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








Table of Contents













PART I




ITEM 1.   BUSINESS




Overview





We are a
publicly traded limited liability company focused on the acquisition and
development of mature, long-lived natural gas and oil properties in the United
States. Our primary business objective is to generate stable cash flows allowing
us to make quarterly cash distributions to our unitholders, and over time to
increase our quarterly cash distributions through the acquisition of new natural
gas and oil properties. Our properties are located in the southern portion of
the Appalachian Basin, primarily in southeast Kentucky and northeast Tennessee,
the Permian Basin, primarily in west Texas and southeastern New Mexico, and in
south Texas.




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




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




On
December 21, 2007, we entered in to a Purchase and Sale Agreement with the
Apache Corporation for the purchase of certain natural gas and oil properties
located in ten separate fields in the Permian Basin of west Texas and
southeastern New Mexico, referred to as the “Permian Basin acquisition.” The
purchase price for said assets was $78.3 million with an effective date of
October 1, 2007. We completed this acquisition on January 31, 2008 for
an adjusted purchase price of $73.4 million, subject to customary post-closing
adjustments. The post-closing adjustments reduced the final purchase price to
$71.5 million and included a purchase price adjustment of $6.8 million for the
cash flow from the acquired properties for the period between the effective
date, October 1, 2007, and the final settlement date. This acquisition was
funded with borrowings under our reserve-based credit facility. Through this
acquisition, we acquired working interests in 390 gross wells (67 net wells), 49
of which we operate. With respect to operations, we have established two
district offices, one in Lovington, New Mexico and the other in Christoval,
Texas to manage these assets. Our operating focus will be on maximizing existing
production and looking for complementary acquisitions that we can add to this
operating platform. With this acquisition, based on internal reserve estimates,
we acquired 4.4 million barrels of oil equivalent, 83% of which is oil and 90%
of which is proved developed producing.





On July
18, 2008, we entered into a Purchase and Sale Agreement with Segundo Navarro
Drilling, Ltd., a wholly owned subsidiary of the Lewis Energy Group, for the
acquisition of certain natural gas and oil properties located in the Dos
Hermanos Field in Webb County, Texas, referred to as the “south Texas
acquisition.” The purchase price for said assets was $53.4 million with an
effective date of June 1, 2008. We completed this acquisition on July 28, 2008
for an adjusted purchase price of $51.4 million, subject to customary
post-closing adjustments to be determined. This acquisition was funded with
$30.0 million of borrowings under our reserve-based credit facility and through
the issuance of 1,350,873 common units of the Company. In this purchase, we
acquired an average of a 98% working interest in 91 producing wells and an
average 47.5% working interest in approximately 4,705 gross acres with 41
identified proved undeveloped locations. An affiliate of Lewis Energy Group
operates all the properties and is contractually obligated to drill seven wells
each year from 2009 through 2011 unless mutually agreed not to do so. Based on
internal reserve estimates, we acquired 20 Bcfe of proved reserves, 98% of which
is natural gas and 65% of which is proved developed producing. Upon closing this
transaction, we assumed natural gas swaps and collars based on Houston Ship
Channel pricing for approximately 85% of the estimated gas production from
existing producing wells for the period beginning July 2008 through December
2011 which had a fair value of $3.6 million on July 28, 2008.





Our
estimated proved reserves at December 31, 2008 were 108.5 Bcfe, of which
approximately 75% were natural gas and 75% were classified as proved developed.
At December 31, 2008, we owned working interests in 1,444 gross (958 net)
productive wells and our average net production for the year ended
December 31, 2008 was 16,206 Mcfe per day. We also have a 40% working
interest in approximately 109,500 gross undeveloped acres surrounding or
adjacent to our existing wells located in southeast Kentucky and northeast
Tennessee. As mentioned above, Vinland owns the remaining 60% working interest
in this acreage. Approximately 25%, or




1
 Table of Contents


27.6
Bcfe, of our estimated proved reserves as of December 31, 2008 were
attributable to this 40% working interest. In addition, we own a contract right
to receive approximately 99% of the net proceeds from the sale of production
from certain oil and gas wells located in Bell and Knox Counties, Kentucky,
which accounted for approximately 2.6% of our estimated proved reserves as of
December 31, 2008. Our wells and undeveloped leasehold acreage in
Appalachia fall within an approximate 750,000 acre area, which we refer to in
this Annual Report as the “area of mutual interest,” or AMI. We have agreed with
Vinland until January 1, 2012 to offer the other the right to participate
in any acquisition, exploitation and development opportunities that arise in the
AMI, subject however to Vinland’s right to consummate up to two acquisitions
with a purchase price of $5.0 million or less annually without a requirement to
offer us the right to participate in such acquisitions. In south Texas, we own
working interests ranging from 45-50% in approximately 5,300 undeveloped acres
surrounding our existing wells.




Our
average proved reserves-to-production ratio, or average reserve life, is
approximately 18 years based on our proved reserves as of December 31,
2008. During 2008, we drilled 87 gross wells (39 net wells) and as of
December 31, 2008, we had identified 352 additional proved undeveloped
drilling locations and over 252 other drilling locations on our leasehold
acreage. Pursuant to a participation agreement that we have entered into with
Vinland, Vinland generally has control over our drilling program in Appalachia
and has the sole right to determine which wells are drilled in Appalachia until
January 1, 2011. During this period we will meet with Vinland on a
quarterly basis to review Vinland’s proposal to drill not less than 25 nor more
than 40 gross wells, in which we will own a 40% working interest, in any
quarter. Up to 20% of the proposed wells may be carried over and added to the
wells to be drilled in the subsequent quarter, provided that Vinland is required
to drill at least 100 gross wells per calendar year. If Vinland proposes the
drilling of less than 25 gross wells in any quarter, we have the right to
propose the drilling of up to a total of 14 net wells, in which we will own a
100% working interest, in a given quarterly period. If either party elects not
to participate in the drilling of the proposed wells or future operations with
respect to drilled wells and such drilling or operations are performed within
the calendar quarter, as proposed, such party forfeits all right, title and
interest in the natural gas and oil production that may be produced from such
wells. Notwithstanding the foregoing, if both parties agree, no drilling is
required. We anticipate that, given existing market conditions, neither party
will propose or participate in drilling until favorable conditions for drilling
exist. The participation agreement will remain in place for four years and shall
continue thereafter on a year to year basis until such time as either party
elects to terminate the agreement. The obligations of the parties with respect
to the drilling program described above will expire in three years, after which
we each will have the right to propose the drilling of wells within the AMI and
offer participation in such proposed drilling to the other party and if either
party elects not to participate in such proposed drilling or future operations
with respect to drilled wells, such party forfeits all right, title and interest
in the natural gas and oil production that may be produced from such
wells.





Disruption
to Functioning of Capital Markets





Multiple
events during 2008 involving numerous financial institutions have effectively
restricted current liquidity within the capital markets throughout the United
States and around the world. Despite efforts by treasury and banking regulators
in the United States, Europe and other nations around the world to provide
liquidity to the financial sector, capital markets currently remain constrained.
We expect that our ability to raise debt and equity at prices that are similar
to offerings in recent years to be limited as long as the capital markets remain
constrained.





During
2008, our unit price closed at a high of $18.41 on May 20, 2008 and our unit
price declined to a closing low of $4.72 on December 23, 2008, which is the
lowest our unit price has closed at since our initial public offering. Since
that date our unit price has partially recovered to a level of $8.85 on March 5,
2009. We intend to move forward with our development drilling program when
market conditions allow for an adequate return on the drilling investment and
only when we have sufficient liquidity to do so. Maintaining adequate liquidity
may involve the issuance of debt and equity at less attractive terms, could
involve the sale of non-core assets and could require reductions in our capital
spending.  In the near-term we will focus on maximizing returns on
existing assets by managing our costs and selectively deploying capital to
improve existing production.





Business
      Strategies





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




·
      Manage our natural gas and oil assets with a focus on maintaining
      production levels and optimizing cash flows by monitoring lease operating
      costs;





·
      Replace reserves either through the development of our extensive inventory
      of proved undeveloped locations or make accretive acquisitions of natural
      gas and oil properties in the known producing basins of the continental
      United States


characterized by a high percentage of
      producing reserves, long-life, stable production and step-out
      development opportunities;


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




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









2
 Table of Contents




Our Relationship with
      Vinland





General. Nami
owns 90% of Vinland, and Nami and certain of his affiliates and related persons
own a 26.8% membership interest in us. Vinland’s senior management team has
extensive experience operating in the Appalachian Basin and has operated our
assets on behalf of our Predecessor in southeast Kentucky and northeast
Tennessee since 1999. As of December 31, 2008, Vinland operated
substantially all of our wells in Appalachia. As of December 31, 2008,
Vinland had assets consisting of production from their 60% working interest in
new wells drilled in 2007 and 2008, a 60% working interest in approximately
109,500 gross undeveloped acres in the AMI, interests in an additional 125,000
undeveloped acres and certain coalbed methane gas rights located in the
Appalachian Basin, the rights to any natural gas and oil located on our acreage
at depths above and 100 feet below our known producing horizons and certain
gathering and compression assets. Vinland intends to rely on contributions from
Nami to fund its proportionate share of our drilling program but Nami has no
obligation to make such contributions to Vinland.




Participation Agreement. Pursuant to a
participation agreement that we have entered into with Vinland, Vinland has
general control over our drilling program in Appalachia and has the sole right
to determine which wells are drilled until January 1, 2011. During this
period, when favorable conditions for drilling exist, we will meet with Vinland
on a quarterly basis to review Vinland’s proposal to drill not less than 25 nor
more than 40 gross wells, in which we will own a 40% working interest, in any
quarter. Up to 20% of the proposed wells may be carried over and added to the
wells to be drilled in the subsequent quarter, provided that Vinland is required
to drill at least 100 gross wells per calendar year. If Vinland proposes the
drilling of less than 25 gross wells in any quarter, we have the right to
propose the drilling of up to a total of 14 net wells during such quarter, in
which we will own a 100% working interest. If either party elects not to
participate in the drilling of the proposed wells or future operations with
respect to drilled wells and such drilling or operations are performed within
the calendar quarter, as proposed, such party forfeits all right, title and
interest in the natural gas and oil production that may be produced from such
wells. We anticipate that, given existing market conditions, neither party will
propose or participate in drilling until favorable conditions for drilling
exist. The participation agreement will remain in place for four years and shall
continue thereafter on a year to year basis until such time as either party
elects to terminate the agreement. The obligations of the parties with respect
to the drilling program described above will expire in three years.




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




Under a
management services agreement, Vinland will advise and consult with us regarding
all aspects of our production and development operations and provide us with
administrative support services as necessary for the operation of our business.
Vinland may, but does not have any obligation to, provide us with acquisition
services under the management services agreement.




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





We also
assumed certain transportation agreements that Vinland had with Delta Natural
Gas with respect to volumes of gas produced in Kentucky. Delta receives gas from
various interconnects with Vinland and redelivers said volumes to Columbia Gas
Transmission. We currently pay Delta $0.27 per MMBtu plus a fuel charge equal to
2% of volume for this transportation service.




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




Our
relationship with Vinland is a source of potential conflicts. For example,
neither Vinland, nor any of its affiliates, is restricted from competing with
us. Vinland or its affiliates may acquire or invest in natural gas and oil
properties or other assets outside of the area of mutual interest in the future
without any obligation to offer us the opportunity to purchase or own interests
in those assets.


Natural
      Gas and Oil Prices





The
Appalachian Basin is a mature producing region with well known geologic
characteristics. Reserves in the Appalachian Basin typically have a high degree
of step-out development success; that is, as development progresses, reserves
from newly completed wells are reclassified from the proved undeveloped to the
proved developed category and additional adjacent locations are added to proved
undeveloped reserves. As a result, the cumulative amount of total proved
reserves tends to increase as development progresses.




3
 Table of Contents


Wells in
the Appalachian Basin generally produce little or no water, contributing to a
low cost of operation. In addition, most wells produce dry natural gas, which
does not require processing. Natural gas produced in the Appalachian Basin
typically sells for a premium to New York Mercantile Exchange, or “NYMEX,”
natural gas prices due to the proximity to major consuming markets in the
northeastern United States. For the year ended December 31, 2008, the
average premium over NYMEX for natural gas delivered to our primary delivery
points in the Appalachian Basin on the Columbia Gas Transmission system was
$0.34 per MMBtu. In addition, most of our natural gas production has
historically had a high Btu content, resulting in an additional premium to NYMEX
natural gas prices. For the year ended December 31, 2008, our average
realized natural gas prices in Appalachia (before hedging), represented a $1.87
per Mcfe premium to NYMEX natural gas prices, which accounts for both the basis
differential and the Btu adjustments.




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





In south
Texas, our natural gas production has a high Btu content and requires some
processing prior to sale to third parties. Through our relationship with the
operator of the south Texas properties, Lewis Petro Properties, Inc. (“Lewis”),
we benefit from a processing agreement that was in place prior to our
acquisition of these natural gas properties. Our proportionate share of the gas
volumes are sold at the tailgate of the processing plant at the Houston Ship
Channel Index price which typically results in a discount to NYMEX prices;
however, with our share of the natural gas liquids associated with the
processing of such gas, our revenues on an Mcf basis are a premium to the NYMEX
prices.





Our
oil production, both in Appalachia and the Permian Basin, is sold under
month-to-month sales contracts with purchasers that take delivery of the oil
volumes at the tank batteries adjacent to the producing wells. Our pricing for
oil sales is based on the monthly average of the West Texas Intermediate Price,
or “WTI,” as posted for the various regions and published by Plains Marketing,
LP, ConocoPhillips or a similar large purchaser of oil, less a transportation or
quality differential which corresponds to the field location or type of oil
being produced. In Appalachia, we have historically received the average WTI
price less $9.93. Since our ownership in 2008 in the Permian Basin, we have
received the average WTI price less $3.62.




We enter
into derivative transactions in the form of hedging arrangements to reduce the
impact of natural gas and oil price volatility on our cash flow from operations.
Currently, we use fixed-price swaps and NYMEX collars and put options to hedge
natural gas and oil prices. By removing the price volatility from a significant
portion of our natural gas and oil production, we have mitigated, but not
eliminated, the potential effects of fluctuation in natural gas and oil prices
on our cash flow from operations. For a description of our derivative positions,
please read “Item 7A—Quantitative and Qualitative Disclosures About Market
Risk.”




Natural
      Gas and Oil Data





Proved
      Reserves




The
following table presents our estimated net proved natural gas and oil reserves
and the present value of the estimated proved reserves at December 31,
2008, based on a reserve report prepared by Netherland, Sewell &
Associates, Inc., or “NSAI.” The estimate of net proved reserves has not been
filed with or included in reports to any federal authority or agency. The
Standardized Measure value shown in the table is not intended to represent the
current market value of our estimated natural gas and oil reserves.




As
      of
                      December
      31,
                      2008Reserve
      Data:Estimated
      net proved reserves:Natural
      gas (Bcf)
                    
                    81.2Crude
      oil (MBbls)
                    
                    4,547Total
      (Bcfe)
                    
                    108.5Proved
      developed (Bcfe)
                    
                    80.9Proved
      undeveloped (Bcfe)
                    
                    27.6Proved
      developed reserves as % of total proved reserves
                    
                    75
                    %Standardized
      measure (in millions) (1)
                    
                    $
                    190.1Representative
      Natural Gas and Oil Prices (2):Natural
      gas—Spot Henry Hub per MMBtu
                    
                    $
                    5.71Oil—WTI
      per Bbl
                    
                    $
                    41.00













4
 Table of Contents





(1) Does not
      give effect to hedging transactions. For a description of our hedging
      transactions, please read “Item 7A—Quantitative and Qualitative
      Disclosures About Market Risk.”




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




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




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




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




From time
to time, we engage NSAI to prepare a reserve and economic evaluation of
properties that we are considering purchasing. Neither NSAI nor any of their
respective employees has any interest in those properties and the compensation
for these engagements is not contingent on their estimates of reserves and
future net revenues for the subject properties. During 2008, we paid NSAI
approximately $145,000 for all reserve and economic evaluations.





Production
      and Price History





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






Year Ended December 31,Vanguard
                      
                      Vanguard
                        Predecessor2008
                      
                      
                      2007
                      
                      
                      2006Net
      Production:Total
      realized production (MMcfe)
                      
                      
                      5,931
                      
                      
                      
                      4,238
                      
                      
                      
                      4,378Average
      daily production (Mcfe/day)
                      
                      
                      16,206
                      (a)
                      
                      
                      11,610
                      
                      
                      
                      11,995Average
      Realized Sales Prices ($ per Mcfe):Average
      sales prices (including hedges)
                      
                      $
                      11.43
                      (b)
                      
                      $
                      8.99
                      (b)
                      
                      $
                      8.22Average
      sales prices (excluding hedges)
                      
                      $
                      11.61
                      
                      
                      $
                      8.15
                      
                      
                      $
                      8.72Average
      Unit Costs ($ per Mcfe):Production
      costs
                      
                      $
                      2.71
                      
                      
                      $
                      1.68
                      
                      
                      $
                      1.52Selling,
      general and administrative expenses
                      
                      $
                      1.13
                      (c)
                      
                      $
                      0.83
                      (c)
                      
                      $
                      1.19Depreciation,
      depletion, amortization and accretion
                      
                      $
                      2.51
                      
                      
                      $
                      2.12
                      
                      
                      $
                      1.97










(a)
      Average daily production for 2008 calculated based on 366 days including
      production for the Permian Basin and south Texas acquisitions from the
      closing dates of these
acquisitions.





(b)Excludesamortization ofpremiums paidand non-cash settlementon
      derivativecontracts.





(c) Includes
      $3.6 million ($.60/Mcfe) and $2.1 million ($0.51/Mcfe) of non-cash
      unit-based compensation expense in 2008 and 2007,
      respectively.









5
 Table of Contents




Productive
      Wells





The
following table sets forth information at December 31, 2008 relating to the
productive wells in which we owned a working interest as of that date.
Productive wells consist of producing wells and wells capable of production,
including natural gas wells awaiting pipeline connections to commence deliveries
and oil wells awaiting connection to production facilities. Gross wells are the
total number of producing wells in which we have an interest, and net wells are
the sum of our fractional working interests owned in gross wells.




Natural
      Gas Wells
                
                
                Oil
      Wells
                
                
                TotalGross
                
                
                Net
                
                
                Gross
                
                
                Net
                
                
                Gross
                
                
                NetOperated
                
                
                32
                
                
                
                30
                
                
                
                39
                
                
                
                35
                
                
                
                71
                
                
                
                65Non-operated
                
                
                1,006
                
                
                
                864
                
                
                
                367
                
                
                
                29
                
                
                
                1,373
                
                
                
                893Total
                
                
                1,038
                
                
                
                894
                
                
                
                406
                
                
                
                64
                
                
                
                1,444
                
                
                
                958








Developed
      and Undeveloped Acreage





The
following table sets forth information as of December 31, 2008 relating to
our leasehold acreage.




Developed Acreage (1)
                
                
                Undeveloped
                  Acreage (2)
                
                
                Total AcreageGross (3)
                
                
                Net (4)
                
                
                Gross (3)
                
                
                Net (4)
                
                
                Gross
                
                
                NetOperated
                
                
                9,547
                
                
                
                6,683
                
                
                
                7,653
                
                
                
                6,039
                
                
                
                17,200
                
                
                
                12,722Non-operated
                
                
                25,520
                
                
                
                22,734
                
                
                
                109,491
                
                
                
                44,787
                
                
                
                135,011
                
                
                
                67,521






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





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





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




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





Drilling
      Activity





Most of
our wells in Appalachia are relatively shallow, ranging from 2,500 to 4,500
feet, and drill through as many as ten potential producing zones. Many of our
wells are completed to multiple producing zones and production from these zones
may be commingled. Our average well in Appalachia takes 10 days to drill and
most of our wells are producing and connected to a pipeline within 30 days after
completion. In general, our producing wells in Appalachia have stable production
profiles and long-lived production, often with total projected economic lives in
excess of 50 years. Once drilled and completed, operating and maintenance
requirements for producing wells in the Appalachian Basin are generally low and
only minimal, if any, capital expenditures are required. In 2009, in Appalachia,
we and our operating partner, Vinland, plan to focus our efforts on
re-completions and operational items that do not require substantial capital
investment but will enhance production from existing wells.




In the
Permian Basin acquisition, we acquired four development drilling locations. In
2008, we drilled one of these locations with a 100% working interest and
participated in two additional wells, offsetting a third party’s producing well
with a 50% working interest.  These projected wells range in depth
from 8,000 to 11,000 feet and target multiple producing horizons. These
wells are estimated to each cost between $0.7 million to $1.0 million to drill
and complete, depending on the total depth targeted.




In the
south Texas acquisition, we acquired a 45-50% working interest in 39 identified
proved undeveloped locations that we and the operator, Lewis, plan to jointly
develop over the next five years. In 2008, we jointly drilled four wells, all of
which were successfully completed. In the current commodity price environment,
we and Lewis have elected to defer drilling additional development wells until
such time as rig and service costs decline to a point where drilling operations
will generate acceptable economic returns.




When we
resume drilling operations, we intend to concentrate our drilling activity on
lower risk, development properties. The number and types of wells we drill will
vary depending on the amount of funds we have available for drilling, the cost
of each well,




6
 Table of Contents




the size
of the fractional working interests we acquire in each well and the estimated
recoverable reserves attributable to each well.




The
following table sets forth information with respect to wells completed during
the years ended December 31, 2008, 2007 and 2006. The information should
not be considered indicative of future performance, nor should it be assumed
that there is necessarily any correlation between the number of productive wells
drilled, quantities of reserves found or economic value. Productive wells are
those that produce commercial quantities of natural gas, regardless of whether
they produce a reasonable rate of return.




Year Ended December 31,Vanguard
                  
                  
                  Vanguard
      Predecessor2008
                  
                  
                  2007
                  
                  
                  2006Gross
      wells:Productive
                  
                  
                  86
                  
                  
                  
                  82
                  
                  
                  
                  100Dry
                  
                  
                  1
                  
                  
                  
                  1
                  
                  
                  
                  —Total
                  
                  
                  87
                  
                  
                  
                  83
                  
                  
                  
                  100Net
      Development wells:Productive
                  
                  
                  38
                  
                  
                  
                  33
                  
                  
                  
                  96Dry
                  
                  
                  1
                  
                  
                  
                  —
                  
                  
                  
                  —Total
                  
                  
                  39
                  
                  
                  
                  33
                  
                  
                  
                  96Net
      Exploratory wells:Productive
                  
                  
                  —
                  
                  
                  
                  —
                  
                  
                  
                  4Dry
                  
                  
                  —
                  
                  
                  
                  —
                  
                  
                  
                  —Total
                  
                  
                  —
                  
                  
                  
                  —
                  
                  
                  
                  4





Operations




Principal
      Customers





For the
year ended December 31, 2008, sales of natural gas and oil to Seminole
Energy Services, Osram Sylvania, Inc., BP Energy Company, Plains
Marketing L.P. and Sunoco Partners Marketing and Terminals, L.P. accounted
for approximately 52%, 15%, 10%, 7% and 4%, respectively, of our natural gas and
oil revenues. Our top five purchasers during the year ended December 31,
2008, therefore accounted for 88% of our total revenues. To the extent these and
other customers reduce the volumes of natural gas and oil that they purchase
from us and they are not replaced in a timely manner with a new customer, our
revenues and cash available for distribution could decline. However, if we were
to lose a customer, we believe we could identify a substitute purchaser in a
timely manner.




Price
      Risk Management Activities





We enter
into derivative contracts with respect to a portion of our projected natural gas
and oil production through various transactions that mitigate the volatility of
future prices received. These transactions may include price swaps whereby we
will receive a fixed-price for our production and pay a variable market price to
the contract counterparty. Additionally, we have put options for which we pay
the counterparty an option premium, equal to the fair value of the option at the
purchase date. At the settlement date we receive the excess, if any, of the
fixed floor over the floating rate. Furthermore, we may enter into collars where
we pay the counterparty if the market price is above the ceiling price and the
counterparty pays us if the market price is below the floor price on a notional
quantity. These activities are intended to support our realized commodity prices
at targeted levels and to manage our exposure to natural gas and oil price
fluctuations. It is never management’s intention to hold or issue derivative
instruments for speculative trading purposes. Conditions sometimes arise where
actual production is less than estimated, which has, and could result in
overhedged volumes. The following table summarizes commodity derivative
contracts in place at December 31, 2008:




2009
                        
                        
                        2010
                        
                        
                        2011
                        
                        
                        2012Gas
      Positions:Fixed
      Price Swaps:Notional
      Volume (MMBtu)
                        
                        
                        3,629,946
                        
                        
                        
                        3,236,040
                        
                        
                        
                        2,962,312
                        
                        
                        
                        —Fixed
      Price ($/MMBtu)
                        
                        $
                        9.42
                        
                        
                        $
                        9.10
                        
                        
                        $
                        7.82
                        
                        
                        $
                        —Puts:Notional
      Volume (MMBtu)
                        
                        
                        840,143
                        
                        
                        
                        —
                        
                        
                        
                        —
                        
                        
                        
                        —   7
 Table of Contents
  Floor
      Price ($/MMBtu)
                        
                        $
                        7.50
                        
                        
                        $
                        —
                        
                        
                        $
                        —
                        
                        
                        $
                        —Collars:Notional
      Volume (MMBtu)
                        
                        
                        1,000,000
                        
                        
                        
                        730,000
                        
                        
                        
                        —
                        
                        
                        
                        —Floor
      Price ($/MMBtu)
                        
                        $
                        7.50
                        
                        
                        $
                        8.00
                        
                        
                        $
                        —
                        
                        
                        $
                        —Ceiling
      Price ($/MMBtu)
                        
                        $
                        9.00
                        
                        
                        $
                        9.30
                        
                        
                        $
                        —
                        
                        
                        $
                        —Total:Notional
      Volume (MMBtu)
                        
                        
                        5,470,089
                        
                        
                        
                        3,966,040
                        
                        
                        
                        2,962,312
                        
                        
                        
                        —Oil
      Positions:Fixed
      Price Swaps:Notional
      Volume (Bbls)
                        
                        
                        181,500
                        
                        
                        
                        164,250
                        
                        
                        
                        151,250
                        
                        
                        
                        144,000Fixed
      Price ($/Bbl)
                        
                        $
                        87.23
                        
                        
                        $
                        85.65
                        
                        
                        $
                        85.50
                        
                        
                        $
                        80.00Collars:Notional
      Volume (Bbls)
                        
                        
                        36,500
                        
                        
                        
                        —
                        
                        
                        
                        —
                        
                        
                        
                        —Floor
      Price ($/Bbl)
                        
                        $
                        100.00
                        
                        
                        $
                        —
                        
                        
                        $
                        —
                        
                        
                        $
                        —Ceiling
      Price ($/Bbl)
                        
                        $
                        127.00
                        
                        
                        $
                        —
                        
                        
                        $
                        —
                        
                        
                        $
                        —Total:Notional
      Volume (Bbls)
                        
                        
                        218,000
                        
                        
                        
                        164,250
                        
                        
                        
                        151,250
                        
                        
                        
                        144,000





In
February 2009, we liquidated our 2012 oil swap and entered into new 2010 and
2011 natural gas swap and collar transactions. Specifically, an $8.04 and $7.85
fixed price NYMEX natural gas swap for January through September 2010 and April
through September 2011, respectively, was executed for 2,000 MMBtu/day. In
addition, a 2,000 MMBtu/day NYMEX natural gas collar with a floor price of $7.50
and a ceiling price of $9.00 for October 2010 through March 2011 and October
2011 through December 2011 was executed. These natural gas derivatives were set
at prices above the current market by using the proceeds of the liquidation of
the 2012 oil swap.





We have
also entered into interest rate swaps, which require exchanges of cash flows
that serve to synthetically convert a portion of our variable interest rate
exposures to fixed interest rates.




The
following summarizes information concerning our positions in open interest rate
swaps at December 31, 2008.




Notional
                    Amount
                  
                  Fixed
                    Libor
                    RatesPeriod:January
      1, 2009 to December 10, 2010
                  
                  $
                  10,000,000
                  
                  1.50
                  %January
      1, 2009 to December 20, 2010
                  
                  $
                  10,000,000
                  
                  1.85
                  %January
      1, 2009 to January 31, 2011
                  
                  $
                  20,000,000
                  
                  3.00
                  %January
      1, 2009 to March 31, 2011
                  
                  $
                  20,000,000
                  
                  2.08
                  %January
      1, 2009 to December 10, 2012
                  
                  $
                  20,000,000
                  
                  3.35
                  %January
      1, 2009 to January 31, 2013
                  
                  $
                  20,000,000
                  
                  2.38
                  %January
      1, 2009 to September 10, 2009 (Basis Swap)
                  
                  $
                  20,000,000
                  
                  LIBOR
      1M vs. LIBOR 3MJanuary
      1, 2009 to October 31, 2009 (Basis Swap)
                  
                  $
                  40,000,000
                  
                  LIBOR
      1M vs. LIBOR 3M





Counterparty
Risk




At
December 31, 2008, based upon all of our open derivative contracts shown above
and their respective mark-to-market values, the Company had the following
current and long-term derivative assets and liabilities shown by counterparty
with their March 5, 2009 S&P financial strength rating in
parentheses:




8
 Table of Contents




Citibank,
      N.A. (A+)
                                        
                                        
                                        BNP
      Paribas (AA)
                                        
                                        
                                        The
      Bank of Nova Scotia (AA-)
                                        
                                        
                                        Wachovia
      Bank, N.A. (AA+)
                                        
                                        
                                        TotalCurrent
      Assets
                                        
                                        $
                                        —
                                        
                                        
                                        $
                                        20,636,355
                                        
                                        
                                        $
                                        1,547,293
                                        
                                        
                                        $
                                        —
                                        
                                        
                                        $
                                        22,183,648Current
      Liabilities
                                        
                                        $
                                        (7,800
                                        )
                                        
                                        $
                                        —
                                        
                                        
                                        $
                                        —
                                        
                                        
                                        $
                                        (478,776
                                        )
                                        
                                        $
                                        (486,576
                                        )Long-Term
      Assets
                                        
                                        $
                                        212,133
                                        
                                        
                                        $
                                        15,536,588
                                        
                                        
                                        $
                                        —
                                        
                                        
                                        $
                                        —
                                        
                                        
                                        $
                                        15,748,721Long-Term
      Liabilities
                                        
                                        $
                                        —
                                        
                                        
                                        $
                                        (1,394,750
                                        )
                                        
                                        $
                                        (658,599
                                        )
                                        
                                        $
                                        (259,986
                                        )
                                        
                                        $
                                        (2,313,335
                                        )Total
      Amount Due from Counterparty/(Owed to Counterparty)
                                          at
      December 31, 2008
                                        
                                        $
                                        204,333
                                        
                                        
                                        $
                                        34,778,193
                                        
                                        
                                        $
                                        888,694
                                        
                                        
                                        $
                                        (738,762
                                        )
                                        
                                        $
                                        35,132,458





We net
derivative assets and liabilities for counterparties where we have a legal right
of offset.




Competition


The
natural gas and oil industry is highly competitive. We encounter strong
competition from other independent operators and from major oil companies in
acquiring properties, leasing acreage, contracting for drilling equipment and
securing trained personnel. Many of these competitors have financial and
technical resources and staff substantially larger than ours or a different
business model. As a result, our competitors may be able to pay more for
desirable leases, or to evaluate, bid for and purchase a greater number of
properties or prospects than our financial, technical or personnel resources
will permit.
  We are
also affected by competition for drilling rigs and the availability of related
equipment. In the past, the natural gas and oil industry has experienced
shortages of drilling rigs, equipment, pipe and personnel, which has delayed
development drilling and other exploitation activities and has caused
significant price increases. We are unable to predict when, or if, such
shortages may occur or how they would affect our development and exploitation
program.
  Competition
is also strong for attractive natural gas producing properties, undeveloped
leases and drilling rights, and we cannot assure unitholders that we will be
able to compete satisfactorily when attempting to make further
acquisitions.


Title
      to Properties





As is
customary in the natural gas and oil industry, we initially conduct only a
cursory review of the title to our properties on which we do not have proved
reserves. Prior to the commencement of drilling operations on those properties,
however, we conduct a thorough title examination and perform curative work with
respect to significant defects. To the extent title opinions or other
investigations reflect title defects on those properties, we are typically
responsible for curing any title defects at our expense. We will not commence
drilling operations on a property until we have cured any material title defects
on such property. Prior to completing an acquisition of producing natural gas
and oil leases, we perform title reviews on the most significant leases and,
depending on the materiality of properties, we may obtain a title opinion or
review previously obtained title opinions. As a result, we have obtained title
opinions on a significant portion of our natural gas and oil properties and
believe that we have satisfactory title to our producing properties in
accordance with standards generally accepted in the natural gas and oil
industry. Although title to these properties is subject to encumbrances in some
cases, such as customary interests generally retained in connection with
acquisition of real property, customary royalty interests, contract terms and
restrictions, liens under operating agreements, liens related to environmental
liabilities associated with historical operations, liens for taxes not yet
payable and other burdens, restrictions and minor encumbrances customary in the
natural gas and oil industry, we believe that none of these liens, restrictions,
easements, burdens and encumbrances will materially detract from the value of
these properties or from our interest in these properties, or will materially
interfere with our use of these properties in the operation of our
business.




Seasonal
      Nature of Business





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






9
 Table of Contents




Environmental
      Matters and Regulation







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




·
            require
      the acquisition of various permits and bonds before drilling
      commences;·
            require
      the installation of expensive pollution control
  equipment;·
            restrict
      the types, quantities and concentration of various substances that can be
      released into the environment in connection with drilling and production
      activities;·
            limit
      or prohibit drilling activities on lands lying within wilderness, wetlands
      and other protected areas;·
            require
      remedial measures to prevent pollution from historical and ongoing
      operations, such as pit closure and plugging of abandoned
      wells;·
            impose
      substantial liabilities for pollution resulting from our operations;
      and·
            with
      respect to operations affecting federal lands or leases, require
      preparation of a Resource Management Plan, an Environmental Assessment,
      and/or an Environmental Impact
Statement.










These
laws and regulations may also restrict our ability to produce natural gas and
oil by, among other things, limiting the amount of natural gas and oil we can
produce from our wells, limiting the number of wells we are allowed to drill or
limiting the locations at which we can conduct our drilling operations. The
regulatory burden on the natural gas and oil industry increases the cost of
doing business in the industry and consequently affects profitability.
Additionally, changes in environmental laws and regulations occur frequently,
and any changes that result in more stringent and costly waste handling,
disposal and clean-up requirements for the natural gas and oil industry could
have a significant impact on our operating costs. We believe that operation of
our wells is in substantial compliance with all current applicable environmental
laws and regulations and that our continued compliance with existing
requirements will not have a material adverse impact on our financial condition
and results of operations. However, we cannot provide any assurance on how
future compliance with environmental laws and regulations may impact our
properties or the operations. For the year ended December 31, 2008, we did
not incur any material capital expenditures for installation of remediation or
pollution control equipment at any of our facilities. As of the date of this
Annual Report, we are not aware of any environmental issues or claims that will
require material capital expenditures during 2009 or that will otherwise have a
material impact on our financial position or results of operations.




Environmental
laws and regulations that could have a material impact on our operations as well
as the natural gas and oil exploration and production industry in general
include the following:




National Environmental Policy
Act.   Natural gas and oil exploitation and production
activities on federal lands are subject to the National Environmental Policy
Act, as amended, or “NEPA”. NEPA requires federal agencies, including the
Department of Interior, to evaluate major agency actions having the potential to
significantly impact the environment. In the course of such evaluations, an
agency will typically prepare an Environmental Assessment to assess the
potential direct, indirect and cumulative impacts of a proposed project and, if
necessary, will prepare a more detailed Environmental Impact Statement that may
be made available for public review and comment. Our current exploitation and
production activities, as well as proposed exploitation and development plans,
on federal lands require governmental permits or similar authorizations that are
subject to the requirements of NEPA. This process has the potential to delay,
limit or add to the cost of developing natural gas and oil
projects.




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






10
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wastes
generated by operation of our wells to be significant, any legislative or
regulatory reclassification of natural gas and oil exploitation and production
wastes could increase our costs to manage and dispose of such
wastes.




Hazardous Substance
Releases.   The Comprehensive Environmental Response,
Compensation and Liability Act, as amended, also known as “CERCLA”, or
“Superfund,” and analogous state laws, impose, under certain circumstances,
joint and several liability, without regard to fault or legality of conduct, on
persons who are considered to be responsible for the release of a “hazardous
substance” into the environment. These persons include the owner or operator of
the site where the release occurred and companies that transported or disposed
or arranged for the transportation or disposal of the hazardous substance at the
site. Under CERCLA, such persons may be liable for the costs of cleaning up the
hazardous substances that have been released into the environment, for damages
to natural resources and for the costs of certain health studies. In addition,
it is not uncommon for neighboring landowners and other third parties to file
claims for personal injury and property damage allegedly caused by the hazardous
substances released into the environment. While materials are generated in the
course of operation of our wells that may be regulated as hazardous substances,
we have not received any pending notifications that we may be potentially
responsible for cleanup costs under CERCLA.




We
currently own, lease, or have a non-operating interest in numerous properties
that have been used for natural gas and oil exploitation and production for many
years. Although we believe that operating and waste disposal practices have been
used that were standard in the industry at the time, hazardous substances,
wastes, or petroleum hydrocarbons have been released on or under the properties
owned or leased by us, or on or under other locations, including off-site
locations, where such substances have been taken for disposal. In addition, some
of these properties have been operated by third parties or by previous owners or
operators whose treatment and disposal of hazardous substances, wastes, or
hydrocarbons was not under our control. These properties and the substances
disposed or released on them may be subject to CERCLA, RCRA and analogous state
laws. Under such laws, we could be required to remove previously disposed
substances and wastes, remediate contaminated property, or perform remedial
plugging or pit closure operations to prevent future contamination.




Water Discharges.  
The Federal Water Pollution Control Act, as amended, or “Clean Water Act”, and
analogous state laws impose restrictions and strict controls on the discharge of
pollutants, including produced waters and other natural gas and oil wastes, into
state waters as well as waters of the United States. The discharge of pollutants
into regulated waters is prohibited, except in accordance with the terms of a
permit issued by EPA or the relevant state. The Clean Water Act also prohibits
the discharge of dredge and fill material in regulated waters, including
wetlands, unless authorized by a permit issued by the U.S. Army Corps of
Engineers. Federal and state regulatory agencies can impose administrative,
civil and criminal penalties for non-compliance with discharge permits or other
requirements of the Clean Water Act and analogous state laws and regulations. We
believe that we are in substantial compliance with the requirements of the Clean
Water Act.




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




OSHA.   We are
subject to the requirements of the federal Occupational Safety and Health Act,
as amended, or “OSHA”, and comparable state statutes. The OSHA hazard
communication standard, EPA community right-to-know regulations under the Title
III of CERCLA and similar state statutes require that we organize and/or
disclose information about hazardous materials used or produced in our
operations. We believe that we are in substantial compliance with the applicable
requirements of OSHA.




Climate Change.  In
response to recent studies suggesting that emissions of certain gases, referred
to as “greenhouse gases” and including carbon dioxide and methane, may be
contributing to warming of the Earth’s atmosphere, the current administration
has expressed support for, and it is anticipated that the current session of the
U.S. Congress is considering climate change-related legislation to restrict
greenhouse gas emissions.  In addition, at least one-third of the states,
either individually or through multi-state initiatives, have already taken legal
measures to reduce emissions of greenhouse gases, primarily through the planned
development of greenhouse gas emission inventories and/or greenhouse gas cap and
trade programs. Depending on the particular program, we could be required to
purchase and surrender allowances, for greenhouse gas emissions resulting from
our operations.




Also, as
a result of the U.S. Supreme Court’s decision  in 2007 inMassachusetts, et al. v. EPA
and certain provisions of the Clean Air Act, the EPA may regulate carbon dioxide
and other greenhouse gas emissions from mobile sources such as cars and trucks,
even if Congress does not adopt new legislation specifically addressing
emissions of greenhouse gases. The Court’s holding in theMassachusetts decision that
greenhouse gases including carbon dioxide fall under the federal Clean Air Act’s
definition of “air pollutant” may also result in future regulation of carbon
dioxide and other greenhouse gas emissions from stationary sources under certain
CAA programs. In July 2008, EPA released an “Advance Notice of Proposed
Rulemaking” regarding possible future regulation of greenhouse gas emissions
under the Clean Air Act, in response to the Supreme Court's decision in Massachusetts.






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Although
the notice did not propose any specific, new regulatory requirements for
greenhouse gases, it indicates that federal regulation of greenhouse gas
emissions could occur in the near future even if Congress does not adopt new
legislation specifically addressing emissions of greenhouse gases. New federal,
regional or state laws requiring adoption of a stringent greenhouse gas control
program or imposing restrictions on emissions of carbon dioxide in areas of the
United States in which we conduct business could adversely affect our cost of
doing business and demand for the natural gas and oil we produce.




Other
      Regulation of the Natural Gas and Oil
Industry





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




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




Drilling and
Production.   Our operations are subject to various types of
regulation at the federal, state and local levels. These types of regulation
include requiring permits for the drilling of wells, drilling bonds and reports
concerning operations. Most states, and some counties and municipalities, in
which we operate also regulate one or more of the following:




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





State
laws regulate the size and shape of drilling and spacing units or proration
units governing the pooling of natural gas and oil properties. Some states allow
forced pooling or integration of tracts to facilitate exploitation while other
states rely on voluntary pooling of lands and leases. In some instances, forced
pooling or unitization may be implemented by third parties and may reduce our
interest in the unitized properties. In addition, state conservation laws
establish maximum rates of production from natural gas and oil wells, generally
prohibit the venting or flaring of natural gas and impose requirements regarding
the ratability of production. These laws and regulations may limit the amount of
natural gas and oil we can produce from our wells or limit the number of wells
or the locations at which we can drill. Moreover, each state generally imposes a
production or severance tax with respect to the production and sale of oil,
natural gas and natural gas liquids within its jurisdiction.




Regulation of Transportation
and Sales.   The availability, terms and cost of transportation
significantly affect sales of natural gas and oil. The interstate transportation
of natural gas is subject to federal regulation primarily by the Federal Energy
Regulatory Commission, or “FERC” under the Natural Gas Act of
1938.  FERC regulates interstate natural gas pipeline transportation
rates and service conditions, which may affect the marketing and sales of
natural gas.  FERC requires interstate pipelines to offer available
firm transportation capacity on an open-access, non-discriminatory basis to all
natural gas shippers.  FERC frequently reviews and modifies its
regulations regarding the transportation of natural gas with the stated goal of
fostering competition within all phases of the natural gas
industry.  State laws and regulations generally govern the gathering
and intrastate transportation of natural gas. Natural gas gathering systems in
the states in which we operate are generally required to offer services on a
non-discriminatory basis, and are subject to state ratable take and common
purchaser statutes.  Ratable take statutes generally require gatherers
to take, without undue discrimination, natural gas production that may be
tendered to the gatherer for handling.  Similarly, common purchaser
statutes generally require gatherers to purchase without discrimination in favor
of one producer over another producer or one source of supply over another
source of supply.




The
ability to transport oil is generally dependent on pipelines whose rates, terms
and conditions of service are subject to FERC jurisdiction under the Interstate
Commerce Act, or subject to regulation by the particular state in which such
transportation takes place.  Laws and regulation applicable to
pipeline transportation of oil largely require pipelines to charge rates
published in agency-


12
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approved
tariffs and require pipelines to provide non-discriminatory access and terms and
conditions of service.  Certain regulations imposed by FERC, by the
United States Department of Transportation and by other regulatory authorities
on pipeline transporters in recent years could result in an increase in the cost
of pipeline transportation service.  We do not believe, however, that
these regulations affect us any differently than other producers.





Under the
Energy Policy Act of 2005, or “EPAct 2005,” Congress made it unlawful for any
entity, as defined in the EPAct 2005, including otherwise non-jurisdictional
producers such as us, to use any deceptive or manipulative device or contrivance
in connection with the purchase or sale of natural gas or the purchase or sale
of transportation services regulated by the FERC that violates the FERC’s rules.
FERC’s  rules implementing  EPAct of 2005 make it
unlawful for any entity, directly or indirectly, to use or employ any device,
scheme, or artifice to defraud; to make any untrue statement of material fact or
omit to make any such statement necessary to make the statements made not
misleading; or to engage in any act or practice that operates as a fraud or
deceit upon any person in connection with the purchase or sale of natural gas
subject to the jurisdiction of the FERC, or the purchase or sale of
transportation services subject to the jurisdiction of the FERC. EPAct 2005 also
gives the FERC authority to impose civil penalties for violations of the NGA up
to $1,000,000 per day per violation. Pursuant to authority granted to FERC by
EPAct 2005, FERC has also put in place additional regulations intended to
prevent market manipulation and to promote price transparency.  For
example, FERC has imposed new rules requiring wholesale purchasers and sellers
of natural gas to report to FERC certain aggregated volume and other purchase
and sales data for the previous calendar year. While EPAct 2005 reflects a
significant expansion of the FERC’s enforcement authority, we do not anticipate
that we will be affected by EPAct 2005 any differently than energy industry
participants.




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




The
various states regulate the drilling for, and the production, gathering and sale
of, natural gas and oil, including imposing severance and other production
related taxes and requirements for obtaining drilling permits. For example,
currently, a severance tax on natural gas and oil production is imposed at a
rate of 4.5%, 3.0% and 3.75% in Kentucky, Tennessee and New Mexico,
respectively. Texas currently imposes a 7.5% severance tax on gas production and
4.6% severance tax on oil production. States also regulate the method of
developing new fields, the spacing and operation of wells and the prevention of
waste of natural gas resources. States may regulate rates of production and may
establish maximum daily production allowables from natural gas and oil wells
based on market demand or resource conservation, or both. States do not
currently regulate wellhead prices or engage in other similar direct economic
regulation, but there can be no assurance that they will not do so in the
future. The effect of these regulations may be to limit the amounts of natural
gas or oil that may be produced from our wells, to increase our cost of
production, to limit the number of wells or locations we can drill and to limit
the availability of pipeline capacity to bring our products to
market.




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




Employees





As of
December 31, 2008, we had ten full time employees. Eight of our employees
work in our Houston office, one employee works in our office in Lovington, New
Mexico and the other in our office in Christoval, Texas. Under the management
services agreement with Vinland, we rely on Vinland’s employees to operate our
existing producing wells in Appalachia and coordinate our development drilling
program in Appalachia. In connection with the Permian Basin acquisition, we
outsourced the production accounting to a third party and began operating our
own wells. With respect to the south Texas properties, the operator manages the
operations of all our wells and coordinates any drilling operations that might
be conducted on the jointly owned leasehold interests. We also contract for the
services of independent consultants involved in land, regulatory, tax,
accounting, financial and other disciplines as needed. None of our employees are
represented by labor unions or covered by any collective bargaining agreement.
We believe that our relations with our employees are satisfactory.




Offices





We
entered into a lease agreement in February 2009 for approximately 8,645 square
feet of office space in Houston, Texas. The lease for our Houston office expires
in April 2010.






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ITEM 1A.   RISK FACTORS





Risks
      Related to Our Business





We
may not have sufficient cash from operations to pay quarterly distributions on
our common units following establishment of cash reserves and payment of
operating costs.




We may
not have sufficient cash flow from operations each quarter to pay
distributions.  Under the terms of our limited liability company
agreement, the amount of cash otherwise available for distribution will be
reduced by our operating expenses and the amount of any cash reserve amounts
that our board of directors establishes to provide for future operations, future
capital expenditures, future debt service requirements and future cash
distributions to our unitholders. The amount of cash we can distribute on our
common units principally depends upon the amount of cash we generate from our
operations, which will fluctuate from quarter to quarter based on, among other
things:




·
            the
      amount of natural gas and oil we
produce;




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




·
            the
      level of our operating costs;




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




·
            the
      level of our capital expenditures.




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




·
            the
      level of our capital expenditures;




·
            our
      ability to make working capital borrowings under our 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 credit
  facility;




·
            prevailing
      economic conditions; and




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




As a
result of these factors, the amount of cash we distribute in any quarter to our
unitholders may fluctuate significantly from quarter to quarter. If we do not
achieve our expected operational results or cannot borrow the amounts needed, we
may not be able to pay the full, or any, amount of the quarterly distribution,
in which event the market price of our common units may decline
substantially.





We
rely on Vinland, an affiliate of our largest unitholder, to execute our drilling
program in Appalachia. If Vinland fails to or inadequately performs, our
operations will be disrupted and our costs could increase or our reserves may
not be developed, reducing our future levels of production and our cash from
operations, which could affect our ability to make cash distributions to our
unitholders.





Effective
as of January 5, 2007, we entered into various agreements with Vinland, an
affiliate of our largest unitholder, under which we rely on Vinland to operate
all of our existing producing wells and coordinate our development drilling
program in Appalachia. For example, pursuant to a participation agreement that
we have entered into with Vinland, Vinland generally has control over our
drilling program in Appalachia and has the sole right to determine which wells
are drilled until January 1, 2011. Under the agreements, Vinland will also
advise and consult with us regarding all aspects of our production and
development operations in Appalachia and provide us with administrative support
services as necessary or useful for the operation of our business. If Vinland




14
 Table of Contents




fails to
or inadequately performs these functions, our operations in Appalachia will be
disrupted and our costs could increase or our reserves may not be developed or
properly developed, reducing our future levels of production and our cash from
operations, which could affect our ability to make cash distributions to our
unitholders.





We
may not be able to obtain funding, obtain funding on acceptable terms or obtain
funding under our reserve-based credit facility because of the deterioration of
the credit and capital markets. This may hinder or prevent us from meeting our
future capital needs.





Global
financial markets and economic conditions have been, and continue to be,
disrupted and volatile. The debt and equity capital markets have been
exceedingly distressed. These issues, along with significant write-offs in the
financial services sector, the re-pricing of credit risk and the current weak
economic conditions have made, and will likely continue to make, it difficult to
obtain funding.





In
particular, the cost of raising money in the debt and equity capital markets has
increased substantially while the availability of funds from those markets
generally has diminished significantly. Also, as a result of concerns about the
stability of financial markets generally and the solvency of counterparties
specifically, the cost of obtaining money from the credit markets generally has
increased as many lenders and institutional investors have increased interest
rates, enacted tighter lending standards, refused to refinance existing debt at
maturity at all or on terms similar to our current debt and reduced and, in some
cases, ceased to provide funding to borrowers.





In
addition, we may be unable to obtain adequate funding under our reserve-based
credit facility because our lending counterparties may be unwilling or unable to
meet their funding obligations.





Due to
these factors, we cannot be certain that funding will be available if needed and
to the extent required, on acceptable terms. If funding is not available when
needed, or is available only on unfavorable terms, we may be unable to grow our
existing business, complete acquisitions or otherwise take advantage of business
opportunities or respond to competitive pressures, any of which could have a
material adverse effect on our revenues and results of operations.





Growing
the Company will require significant amounts of debt and equity financing, which
may not be available to us on acceptable terms, or at all.





We plan
to fund our growth through acquisitions with proceeds from sales of our debt and
equity securities and borrowings under our reserve-based credit facility;
however, we cannot be certain that we will be able to issue our debt and equity
securities on terms or in the proportions that we expect, or at all, and we may
be unable refinance our reserve-based credit facility when it
expires.





The cost
of raising money in the debt and equity capital markets has increased
substantially while the availability of funds from those markets generally has
diminished significantly. Also, as a result of concerns about the stability of
financial markets generally and the solvency of counterparties specifically, the
cost of obtaining money from the credit markets generally has increased as many
lenders and institutional investors have increased interest rates, imposed
tighter lending standards, refused to refinance existing debt at maturity at all
or on terms similar to our current debt and reduced and, in some cases, ceased
to provide funding to borrowers.





A
significant increase in our indebtedness, or an increase in our indebtedness
that is proportionately greater than our issuances of equity, as well as the
credit market and debt and equity capital market conditions discussed above
could negatively impact our ability to remain in compliance with the financial
covenants under our reserve-based credit facility which could have a material
adverse effect on our financial condition, results of operations and cash flows.
If we are unable to finance our growth as expected, we could be required to seek
alternative financing, the terms of which may not be attractive to us, or not
purse growth opportunities.





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




We are
prohibited from borrowing under our reserve-based credit facility to pay
distributions to unitholders if the amount of borrowings outstanding under our
reserve-based credit facility reaches or exceeds 90% of the borrowing base. Our
borrowing base is the amount of money available for borrowing, as determined
semi-annually by our lenders in their sole discretion. The lenders will
re-determine the borrowing base based on an engineering report with respect to
our natural gas and oil reserves, which will take into account the prevailing
natural gas and oil prices at such time. In the future, we may not be able to
access adequate funding under our reserve-based credit facility as a result of
(i) a decrease in our borrowing base due to the outcome of a subsequent
borrowing base redetermination, or (ii) an unwillingness or inability on
the part of our lending counterparties to meet their funding obligations. In
October 2008, our borrowing base was set at $175.0 million. Our next borrowing
base redetermination is scheduled for April 2009 utilizing our December 31, 2008
reserve report. The recent declines in commodity prices make it likely that we
will be subject to a reduction in our borrowing base at our April 2009 borrowing
base redetermination. A continuing decline in commodity prices could result in a
determination to lower the borrowing base in the future and, in such case, we
could be required to repay any indebtedness in


15
 Table of Contents




excess of
the borrowing base. We anticipate that if, at the time of any distribution, our
borrowings equal or exceed 90% of the then-specified borrowing base, our ability
to pay distributions to our unitholders in any such quarter will be solely
dependent on our ability to generate sufficient cash from our
operations.




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





Natural
gas and oil prices are volatile.  A decline in natural gas and oil
prices could adversely affect our financial position, financial results, cash
flow, access to capital and ability to grow.





Our
future financial condition, revenues, results of operations, rate of growth and
the carrying value of our natural gas and oil properties depend primarily upon
the prices we receive for our natural gas and oil production and the prices
prevailing from time to time for natural gas and oil. Prices also affect our
cash flow available for capital expenditures and our ability to access funds
under our reserve-based credit facility and through the capital markets. The
amount available for borrowing under our reserve-based credit facility is
subject to a borrowing base, which is determined by our lenders taking into
account our estimated proved reserves and is subject to semi-annual
redeterminations based on pricing models determined by the lenders at such time.
The recent decline in natural gas and oil prices has adversely impacted the
value of our estimated proved reserves and, in turn, the market values used by
our lenders to determine our borrowing base. It is likely that we will be
subject to a reduction in our borrowing base at our next scheduled
redetermination in April 2009.  Further, because we have elected to
use the full-cost accounting method, each quarter we must perform a “ceiling
test” that is impacted by declining prices. Significant price declines could
cause us to take one or more ceiling test write downs, which would be reflected
as non-cash charges against current earnings.




Natural
gas and oil prices historically have been volatile and are likely to continue to
be volatile in the future, especially given current geopolitical and economic
conditions.  For example, the NYMEX crude oil spot price per barrel
for the period between January 1, 2008 and December 31, 2008 ranged from a high
of $145.29 to a low of $33.87 and the NYMEX natural gas spot price per MMBtu for
the period January 1, 2008 to December 31, 2008 ranged from a high of $13.58 to
a low of $5.29. As of March 5, 2009, the NYMEX crude oil spot price per barrel
was $43.61 and the NYMEX natural gas spot price per MMBtu was $4.09. This price
volatility affects the amount of our cash flow we have available for capital
expenditures and our ability to borrow money or raise additional
capital.  The prices for natural gas and oil are subject to a variety
of factors, including:





·
            the
      level of consumer demand for natural gas and
  oil;





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





·
            commodity
      processing, gathering and transportation availability, and the
      availability of refining capacity;





·
            the
      price and level of imports of foreign crude natural gas and
      oil;





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





·
            domestic
      and foreign governmental regulations and
taxes;





·
            the
      price and availability of alternative fuel
  sources;





·
            weather
      conditions;





·
            political
      conditions or hostilities in oil and gas producing regions, including the
      Middle East, Africa and South
America;





·
            technological
      advances affecting energy consumption;
and





·
            worldwide
      economic conditions.





Declines
in natural gas and oil prices would not only reduce our revenue, but could
reduce the amount of natural gas and oil that we can produce economically and,
as a result, could have a material adverse effect on our financial condition,
results of operations and reserves.  We recorded a non-cash ceiling
test impairment of natural gas and oil properties for the year ended December
31, 2008 of $58.9 million as a result of a decline in natural gas and oil prices
at the measurement date. If the gas and oil industry experiences significant
price declines, we may, among other things, be unable to maintain or increase
our borrowing capacity, repay current or




16
 Table of Contents




future
indebtedness or obtain additional capital on attractive terms, all of which can
affect the value of our units.




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




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





Future
price declines may result in a write down of our asset carrying
values.




Lower
natural gas and oil prices may not only decrease our revenues, but also reduce
the amount of natural gas and oil that we can produce economically. This may
result in our having to make substantial downward adjustments to our estimated
proved reserves. If this occurs, or if our estimates of development costs
increase, production data factors change or drilling results deteriorate,
accounting rules may require us to write down, as a non-cash charge to
earnings, the carrying value of our natural gas properties for impairments. We
are required to perform impairment tests on our assets whenever events or
changes in circumstances lead to a reduction of the estimated useful life or
estimated future cash flows that would indicate that the carry amount may not be
recoverable or whenever management’s plans change with respect to those assets.
We recorded a non-cash ceiling test impairment of natural gas and oil properties
for the year ended December 31, 2008 of $58.9 million as a result of a decline
in natural gas and oil prices at the measurement date. We may incur additional
impairment charges in the future, which could have a material adverse effect on
our results of operations in the period taken and our ability to borrow funds
under our reserve-based credit facility, which may affect our ability to fund
our operations and acquire additional reserves, which may adversely affect our
ability to make cash distributions to our unitholders.




Lower
natural gas and oil prices and other factors have resulted, and in the future
may result, in ceiling test write downs and other impairments of our asset
carrying values.





We use
the full cost method of accounting to report our natural gas and oil properties.
Under this method, we capitalize the cost to acquire, explore for, and develop
natural gas and oil properties. Under full cost accounting rules, the net
capitalized costs of proved natural gas and oil properties may not exceed a
“ceiling limit,” which is based upon the present value of estimated future net
cash flows from proved reserves, discounted at 10%. If net capitalized costs of
proved natural gas and oil properties exceed the ceiling limit, we must charge
the amount of the excess to earnings. This is called a “ceiling test write
down.” Under the accounting rules, we are required to perform a ceiling test
each quarter. A ceiling test write down would not impact cash flow from
operating activities, but it would reduce our members’ equity.





The risk
that we will be required to write down the carrying value of our natural gas and
oil properties increases when oil and gas prices are low or volatile. In
addition, write downs may occur if we experience substantial downward
adjustments to our estimated proved reserves, or if estimated future development
costs increase. For example, natural gas and oil prices declined significantly
throughout the second half of 2008. We recorded a non-cash ceiling test
impairment of natural gas and oil properties for the year ended December 31,
2008 of $58.9 million as a result of a decline in natural gas and oil prices at
the measurement date.  This impairment was calculated based on prices
of $5.71 per MMBtu for natural gas and $41.00 per barrel of crude oil. The
volatility in commodity prices has continued and the conditions in the global
economic markets have continued to deteriorate. These and other factors could
cause us to record additional write downs of our oil and natural gas properties
and other assets in the future and incur additional charges against future
earnings.





Our
acquisition activities will subject us to certain risks.




During
2008, we expanded our operations into the Permian Basin of west Texas and
southeastern New Mexico and into south Texas. Any acquisition involves potential
risks, including, among other things: the validity of our assumptions about
reserves, future production, revenues and costs, including synergies; an
inability to integrate successfully the businesses we acquire; a decrease in our
liquidity by using a significant portion of our available cash or borrowing
capacity to finance acquisitions; a significant increase in our interest expense
or financial leverage if we incur additional debt to finance acquisitions; the
assumption of unknown liabilities, losses




17
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or costs
for which we are not indemnified or for which our indemnity is inadequate; the
diversion of management’s attention to other business concerns; an inability to
hire, train or retain qualified personnel to manage and operate our growing
business and assets; the incurrence of other significant charges, such as
impairment of other intangible assets, asset devaluation or restructuring
charges; unforeseen difficulties encountered in operating in new geographic
areas; an increase in our costs or a decrease in our revenues associated with
any potential royalty owner or landowner claims or disputes; and customer or key
employee losses at the acquired businesses.




Our
decision to acquire a property will depend in part on the evaluation of data
obtained from production reports and engineering studies, geophysical and
geological analyses and seismic and other information, the results of which are
often inconclusive and subject to various interpretations. Also, our reviews of
acquired properties are inherently incomplete because it generally is not
feasible to perform an in-depth review of the individual properties involved in
each acquisition. Even a detailed review of records and properties may not
necessarily reveal existing or potential problems, nor will it permit us to
become sufficiently familiar with the properties to assess fully their
deficiencies and potential. Inspections may not always be performed on every
well, and environmental problems, such as ground water contamination, are not
necessarily observable even when an inspection is undertaken.




If our
acquisitions do not generate increases in available cash per unit, our ability
to make cash distributions to our unitholders could materially
decrease.





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





Pursuant
to a participation agreement that we have entered into with Vinland, Vinland
generally has control over our drilling program in Appalachia and has the sole
right to determine which wells are drilled until January 1, 2011. During
this period, when favorable conditions for drilling exists, we will meet with
Vinland on a quarterly basis to review Vinland’s proposal to drill not less than
25 nor more than 40 gross wells, in which we will own a 40% working interest, in
any quarter. Up to 20% of the proposed wells may be carried over and added to
the wells to be drilled in the subsequent quarter, provided that Vinland is
required to drill at least 100 gross wells per calendar year. If Vinland
proposes the drilling of less than 25 gross wells in any quarter, we have the
right to propose the drilling of up to a total of 14 net wells, in which we will
own a 100% working interest, in a given quarterly period. If Vinland drills its
minimum commitment, we do not have the ability to drill our own additional wells
in the AMI. If either party elects not to participate in the drilling of the
proposed wells or future operations with respect to drilled wells, such party
forfeits all right, title and interest in the natural gas and oil production
that may be produced from such wells. Notwithstanding the foregoing, if both
parties agree, no drilling is required.





A
substantial majority of our properties in the Permian Basin and all of the
properties in south Texas are operated by a third party.  Because we do not
control the development of the non-operated properties, we may not be able to
achieve any production from these non-operated properties in a timely
manner.




We
currently only operate 41 of our 396 gross wells in the Permian Basin and we do
not operate any of the wells in south Texas. In addition, we expect that a
substantial majority of future wells on our existing Permian Basin properties
will be operated by third parties and that all of our future wells in south
Texas will be operated by Lewis.  As a result, the success and timing of
our drilling and development activities on such non-operated properties depend
upon a number of factors, including:




· the nature
      and timing of drilling and operational
  activities;





· the timing
      and amount of capital expenditures;





· the
      operators’ expertise and financial
resources;





· the approval
      of other participants in such properties;
and





· the selection
      of suitable technology.




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




We
could lose our interests in future wells if we fail to participate under our
operating agreement with Lewis in the drilling of these wells.




Under the
terms of our operating agreement with Lewis, we may elect to forego
participation in the future drilling of wells. Should we do so, we will become
obligated to transfer without compensation all of our right, title and interest
in those wells.





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





Effective
January 5, 2007, we entered into several agreements with Vinland pursuant
to which Vinland operates all of our existing producing wells in Appalachia and
coordinates our development drilling program in Appalachia. In addition, Vinland
generally has control over our drilling program in Appalachia and has the sole
right to determine which wells are drilled until January 1, 2011. In the
event Vinland becomes insolvent or is declared bankrupt, we would have to become
the operator of our wells in Appalachia and pursue our own drilling program,
which would require additional employees and increased expenses. In addition,
there are no restrictions on Nami from selling his ownership in Vinland to a
third party that should, but may not perform under our agreements with Vinland.
Any material nonperformance under our agreements with Vinland could materially
and adversely impact our ability to operate and make distributions to our
unitholders.





The
amount of cash that we have available for distribution to our unitholders
depends primarily upon our cash flow and not our profitability.




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




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




No one
can measure underground accumulations of natural gas or oil in an exact way.
Natural gas and oil reserve engineering requires subjective estimates of
underground accumulations of natural gas and/or oil and assumptions concerning
future natural gas and oil prices, production levels, and operating and
development costs. As a result, estimated quantities of proved reserves and
projections of future production rates and the timing of development
expenditures may prove to be inaccurate. Independent petroleum engineers prepare
estimates of our proved reserves. Some of our reserve estimates are made without
the benefit of a lengthy production history, which are less reliable than
estimates based on a lengthy production history. Also, the calculation of
estimated reserves requires certain assumptions regarding future natural gas and
oil prices, production levels, and operating and development costs, any of which
assumptions may prove incorrect. Any significant variance from these assumptions
by actual figures could greatly affect our estimates of reserves, the
economically recoverable quantities of natural gas and oil attributable to any
particular group of properties, the classifications of reserves based on risk of
recovery, and estimates of the future net cash flows. For example, if natural
gas prices decline by $1.00 per MMBtu or 18% and oil prices declined by $6.00
per barrel or 15%, the standardized measure of our proved reserves as of
December 31, 2008 would decrease from $190.1 million to $138.1 million,
based on price sensitivity generated from an internal evaluation. Our
standardized measure is calculated using unhedged natural gas and oil prices and
is determined in accordance with the rules and regulations of the
Securities and Exchange Commission or “SEC.” Numerous changes over time to the
assumptions on which our reserve estimates are based, as described above, often
result in the actual quantities of natural gas and oil we ultimately recover
being different from our reserve estimates.




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




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




·
      the volume, pricing and duration of our natural gas and oil hedging
      contracts;





·
      supply of and demand for natural gas and
oil;





·
      actual prices we receive for natural gas and
  oil;





·
      our actual operating costs in producing natural gas and
    oil;





·
      the amount and timing of our capital
  expenditures;





·
      the amount and timing of actual production;
and





·
      changes in governmental regulations or
taxation.







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




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




The
natural gas and oil industry is capital intensive. We have made and ultimately
expect to continue to make substantial capital expenditures in our business for
the development, production and acquisition of natural gas and oil reserves.
These expenditures will reduce our cash available for distribution. We intend to
finance our future capital expenditures with cash flow from operations and our
financing arrangements. Our cash flow from operations and access to capital are
subject to a number of variables, including:




·
      our proved reserves;





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





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





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





If our
revenues or the borrowing base under our reserve-based credit facility decrease
as a result of lower natural gas and oil prices, operating difficulties,
declines in reserves or for any other reason, we may have limited ability to
obtain the capital necessary to sustain our operations at current levels or to
replace or add to our reserves. Our reserve-based credit facility restricts our
ability to obtain new debt financing. If additional capital is needed, we may
not be able to obtain debt or equity financing on terms favorable to us, or at
all. If cash generated by operations or available under our reserve-based credit
facility is not sufficient to meet our capital requirements, the failure to
obtain additional financing could result in a curtailment of our operations
relating to development of our prospects, which in turn could lead to a possible
decline in our reserves and production and a reduction in our cash available for
distribution.




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




The
marketability of our natural gas production depends in part on the availability,
proximity and capacity of pipeline systems owned by third parties in the
respective operating areas. The amount of natural gas that can be produced and
sold is subject to curtailment in certain circumstances, such as pipeline
interruptions due to scheduled and unscheduled maintenance, excessive pressure,
physical damage to the gathering, compression or transportation system, or lack
of contracted capacity on such systems. The curtailments arising from these and
similar circumstances may last from a few days to several months. In many cases,
we are provided only with limited, if any, notice as to when these circumstances
will arise and their duration. In addition, some of our wells are drilled in
locations that are not serviced by gathering and transportation pipelines, or
the gathering and transportation pipelines in the area may not have sufficient
capacity to transport the additional production. As a result, we may not be able
to sell the natural gas production from these wells until the necessary
gathering and transportation systems are constructed. Any significant
curtailment in gathering system or pipeline capacity, or significant delay in
the construction of necessary gathering, compression and transportation
facilities, could reduce our revenues and cash available for
distribution.




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




For the
year ended December 31, 2008, sales of natural gas and oil to Seminole
Energy Services, Osram Sylvania, Inc., BP Energy Company, Plains
Marketing L.P. and Sunoco Partners Marketing and Terminals, L.P. accounted
for approximately 52%, 15%, 10%, 7% and 4%, respectively, of our natural gas and
oil revenues. Our top five purchasers during the year ended December 31,
2008, therefore accounted for 88% of our total revenues. To the extent these and
other customers reduce the volumes of natural gas and oil that they purchase
from us and they are not replaced in a timely manner with a new customer, our
revenues and cash available for




20
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distribution
could decline.




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




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




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




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





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





·
      CERCLA and comparable state laws that regulate the cleanup of hazardous
      substances that may have been released at properties currently or
      previously owned or operated by us or at locations to which we have sent
      hazardous substances for disposal.





Failure
to comply with these laws and regulations may trigger a variety of
administrative, civil and criminal enforcement measures, including the
assessment of monetary penalties, the imposition of remedial requirements, and
the issuance of orders enjoining future operations. Certain environmental
statutes, including the RCRA, CERCLA, the federal Oil Pollution Act and
analogous state laws and implementing regulations, impose strict, and under
certain circumstances, joint and several liability for costs required to clean
up and restore sites where hazardous substances or wastes have been disposed of
or otherwise released. Moreover, it is not uncommon for neighboring landowners
and other third parties to file claims for personal injury and property or
natural resource damage allegedly caused by the release of hazardous substances
or other waste products into the environment.




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




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




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




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




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





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





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







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




·
      we may incur additional debt related to future
    acquisitions.





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




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




Locations
that we or the operators of our properties decide to drill may not yield natural
gas or oil in commercially viable quantities.





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




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





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




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




Our
management has specifically identified and scheduled drilling locations as an
estimation of our future multi-year drilling activities on our existing acreage.
As of December 31, 2008, we had identified 352 proved undeveloped drilling
locations and over 252 additional drilling locations. These identified drilling
locations represent a significant part of our strategy. We do not intend to
drill any development wells until market conditions allow for an adequate return
on the drilling investment and only when we have sufficient liquidity to do so.
Our ability to drill and develop these locations depends on a number of factors,
including the availability of capital, seasonal conditions, regulatory
approvals, natural gas prices, drilling and operating costs and drilling
results. In addition, NSAI has not assigned any proved reserves to the over 252
unproved drilling locations we have identified and scheduled for drilling and
therefore there may exist greater uncertainty with respect to the success of
drilling wells at these drilling locations. Our final determination on whether
to drill any of these drilling locations will be dependent upon the factors
described above as well as, to some degree, the results of our drilling
activities with respect to our proved drilling locations. Because of these
uncertainties, we do not know if the numerous drilling locations we have
identified will be drilled within our expected timeframe or will ever be drilled
or if we will be able to produce natural gas or oil from these or any other
potential drilling locations. As such, our actual drilling activities may
materially differ from those presently identified, which could adversely affect
our business.




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




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




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






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




We
ordinarily maintain insurance against various losses and liabilities arising
from our operations; however, insurance against all operational risks is not
available to us. Additionally, we may elect not to obtain insurance if we
believe that the cost of available insurance is excessive relative to the
perceived risks presented. Losses could therefore occur for uninsurable or
uninsured risks or in amounts in excess of existing insurance coverage. The
occurrence of an event that is not fully covered by insurance could have a
material adverse impact on our business activities, financial condition and
results of operations.




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




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




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




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




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




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






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We enter
into derivative contracts to reduce the impact of natural gas and oil price
volatility on our cash flow from operations. Currently, we use a combination of
fixed-price swaps and NYMEX collars and put options to mitigate the volatility
of future natural gas and oil prices received. Please read “Item 1—Operations—
Price Risk Management Activities” and “Item 7A—Quantitative and Qualitative
Disclosure About Market Risk.”




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




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




·
      there may be a change in the expected differential between the underlying
      commodity price in the derivative instrument and the actual price
      received; and




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





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





Nami
Resources, LLC, a subsidiary of our Predecessor that was retained by our
founding unitholder, has been involved in an ongoing dispute with Asher Land and
Mineral Company, Ltd., or Asher, pursuant to which Asher claims that Nami
Resources Company, LLC did not correctly calculate the royalties paid to it and
that it failed to abide by certain terms of the leases relating to the
coordination of oil and gas development with coal development activities. As
part of our separation from Vinland, we received from Nami Resources Company,
LLC a contract right to receive approximately 99% of the net proceeds, after
deducting royalties paid to other parties, severance taxes, third-party
transportation costs, costs incurred in the operation of wells and overhead
costs, from the sale of production from certain producing oil and gas wells
located within the Asher lease, which accounted for 2.6% of our proved reserves
as of December 31, 2008. The Asher lease and the litigation related thereto
were retained by Nami Resources Company, LLC. If the Asher lease is terminated
or if Nami Resources Company, LLC rights to production under wells in which we
have a contract right to receive proceeds from the sale of production are
adversely affected, we could lose our contract right to receive proceeds from
the sale of production or it could be adversely affected.





We
are exposed to trade credit risk in the ordinary course of our business
activities.




We are
exposed to risks of loss in the event of nonperformance by our vendors,
customers and by counterparties to our price risk management arrangements. Some
of our vendors, customers and counterparties may be highly leveraged and subject
to their own operating and regulatory risks. Many of our vendors, customers and
counterparties finance their activities through cash flow from operations, the
incurrence of debt or the issuance of equity. Recently, there has been a
significant decline in the credit markets and the availability of credit.
Additionally, many of our vendors’, customers’ and counterparties' equity values
have substantially declined.  The combination of reduction of cash
flow resulting from declines in commodity prices and the lack of availability of
debt or equity financing may result in a significant reduction in our vendors’,
customers’ and counterparties' liquidity and ability to make payments or perform
on their obligations to us.  Even if our credit review and analysis
mechanisms work properly, we may experience financial losses in our dealings
with other parties. Any increase in the nonpayment or nonperformance by our
vendors, customers and/or counterparties could reduce our ability to make
distributions to our unitholders.


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





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




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






24
 Table of Contents




The
natural gas and oil industry is intensely competitive, and we compete with other
companies that have greater resources. Our ability to acquire additional
properties and to discover reserves in the future will be dependent upon our
ability to evaluate and select suitable properties and to consummate
transactions in a highly competitive environment. Many of our larger competitors
not only drill for and produce natural gas and oil, but also carry on refining
operations and market petroleum and other products on a regional, national or
worldwide basis. These companies may be able to pay more for natural gas and oil
properties and evaluate, bid for and purchase a greater number of properties
than our financial or human resources permit. In addition, these companies may
have a greater ability to continue drilling activities during periods of low
natural gas and oil prices and to absorb the burden of present and future
federal, state, local and other laws and regulations. Our inability to compete
effectively with larger companies could have a material adverse impact on our
business activities, financial condition and results of operations.




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




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




Part of
the regulatory environment in which we operate includes, in some cases, legal
requirements for obtaining environmental assessments, environmental impact
studies and/or plans of development before commencing drilling and production
activities. In addition, our activities are subject to the regulations regarding
conservation practices and protection of correlative rights. These regulations
affect our operations and limit the quantity of natural gas we may produce and
sell. A major risk inherent in our drilling plans is the need to obtain drilling
permits from state and local authorities. Delays in obtaining regulatory
approvals or drilling permits, the failure to obtain a drilling permit for a
well or the receipt of a permit with unreasonable conditions or costs could have
a material adverse effect on our ability to develop our properties.
Additionally, the natural gas and oil regulatory environment could change in
ways that might substantially increase the financial and managerial costs of
compliance with these laws and regulations and, consequently, adversely affect
our profitability. At this time, we cannot predict the effect of this increase
on our results of operations. Furthermore, we may be put at a competitive
disadvantage to larger companies in our industry that can spread these
additional costs over a greater number of wells and larger operating staff.
Please read “Item1—Business—Operations—Environmental Matters and Regulation” and
“Business—Operations—Other Regulation of the Natural Gas and Oil Industry” for a
description of the laws and regulations that affect us.




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




Higher
natural gas and oil prices generally increase the demand for drilling rigs,
supplies, services, equipment and crews, and can lead to shortages of, and
increasing costs for, drilling equipment, services and personnel. Over the past
three years, we and other natural gas and oil companies have experienced higher
drilling and operating costs. Shortages of, or increasing costs for, experienced
drilling crews and equipment and services could restrict our ability to drill
the wells and conduct the operations that we currently have planned. Sustained
periods of lower natural gas and oil prices could bring about the closure or
downsizing of entities providing drilling services, supplies, oil field
services, equipment and crews. Any delay in the drilling of new wells or
significant increase in drilling costs could reduce our revenues and cash
available for distribution.




Risks
      Related to Our Structure





Mr. Nami,
who together with certain of his affiliates and related persons, own
approximately 26.8% of our outstanding common units, and a certain member of our
board of directors is a  director of Vinland Energy, LLC
and  may have conflicts of interest with us. The ultimate resolution
of any such conflict of interest may result in favoring the interests of these
other parties over our unitholders’ and may be to our detriment. Our limited
liability company agreement limits the remedies available to our unitholders in
the event unitholders have a claim relating to conflicts of
interest.




One
member of our board of directors is a director of Vinland, which is 90% owned by
Nami. Conflicts of interest may arise between Nami and his affiliates, including
Vinland, and a certain member of our board of directors, on the one hand, and us
and our unitholders, on the other hand. These potential conflicts may relate to
the divergent interests of these parties. Situations in which the interests of
Nami and his affiliates, including Vinland and a certain member of our
board of directors may differ from interests of owners of units include, among
others, the following situations:






25
 Table of Contents




·
            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 in Appalachia;
    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 conflicts of interest that exist or arise in the future our board of
directors or officers, as the case may be, satisfy the applicable standards set
forth in our limited liability company agreement for resolving conflicts of
interest, unitholders will not be able to assert that such resolution
constituted a breach of fiduciary duty owed to us or to unitholders by our board
of directors and officers.


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





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




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




·
            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.




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




Our
limited liability company agreement restricts the voting rights of unitholders
by providing that any units held by a person that owns 20% or more of any class
of units then outstanding, other than our founding unitholder and his affiliates
or transferees and persons who acquire such units with the prior approval of the
board of directors, cannot vote on any matter. Our limited liability agreement
also contains provisions limiting the ability of unitholders to call meetings or
to acquire information about our operations, as well as other provisions
limiting unitholders’ ability to influence the manner or direction of
management.




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




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




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




During
2008, our unit price closed at a high of $18.41 on May 20, 2008 and declined to
a closing low of $4.72 on December 23, 2008. The market price of our common
units is subject to wide fluctuations in response to a number of factors, most
of which we cannot control, including:






26
 Table of Contents




·
            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 general conditions in the U.S. economy, financial markets or the
      natural gas and oil industry;·
            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;·
            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; and·
            future
      issuances and sales of our units.





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




Unitholders
      may have liability to repay
distributions.





Under
certain circumstances, unitholders may have to repay amounts wrongfully returned
or distributed to them. Under Section 18-607 of the Delaware Revised
Limited Liability Company Act, or the “Delaware Act,” we may not make a
distribution to unitholders if the distribution would cause our liabilities to
exceed the fair value of our assets. Delaware law provides that for a period of
three years from the date of an impermissible distribution, members or
unitholders who received the distribution and who knew at the time of the
distribution that it violated Delaware law will be liable to the limited
liability company for the distribution amount. A purchaser of common units who
becomes a member or unitholder is liable for the obligations of the transferring
member to make contributions to the limited liability company that are known to
such purchaser of units at the time it became a member and for unknown
obligations if the liabilities could be determined from our limited liability
company agreement.




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





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




Tax
      Risks to Unitholders





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




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




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






27
 Table of Contents
  If we
were treated as a corporation for federal income tax purposes, we would pay
federal income tax on our taxable income at the corporate tax rates, currently
at a maximum rate of 35%, and would likely pay state income tax at varying
rates. Distributions to unitholders would generally be taxed again as corporate
distributions, and no income, gain, loss, deduction or credit would flow through
to unitholders. Because a tax may be imposed on us as a corporation, our cash
available for distribution to our unitholders could be reduced. Therefore,
treatment of us as a corporation would result in a material reduction in the
anticipated cash flow and after-tax return to our unitholders, likely causing a
substantial reduction in the value of our common units.
  Current
law or our business may change so as to cause us to be treated as a corporation
for federal income tax purposes or otherwise subject us to entity-level
taxation. At the federal level, legislation has been recently considered that
would have eliminated partnership tax treatment for certain publicly traded
LLCs.  Although such legislation would not have appeared to have applied to
us as currently proposed, it could be reconsidered in a manner that would apply
to us.  We are unable to predict whether any of these changes or other
proposals will be reintroduced or will ultimately be enacted.  Moreover,
any modification to the federal income tax laws and interpretations thereof may
or may not be applied retroactively.  Any such changes could negatively
impact the value of an investment in our units.  At the state level,
because of widespread state budget deficits and other reasons, several states
are evaluating ways to subject partnerships and limited liability companies to
entity-level taxation through the imposition of state income, franchise or other
forms of taxation.   For example, we are required to pay Texas
franchise tax which is assessed on Texas sourced taxable margin defined as the
lesser of (i) 70% of total revenue or (ii) total revenue less
(a) cost of goods sold or (b) compensation and benefits.  If any
other state were to impose a tax upon us as an entity, the cash available for
distribution to unitholders would be reduced.


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




We have
not requested a ruling from the IRS with respect to our treatment as a
partnership for federal income tax purposes or any other matter that affects us.
The IRS may adopt positions that differ from the positions we take. It may be
necessary to resort to administrative or court proceedings to sustain some or
all of the positions we take and a court may disagree with some or all of those
positions. Any contest with the IRS may materially and adversely impact the
market for our units and the price at which they trade. In addition, our costs
of any contest with the IRS will result in a reduction in cash available for
distribution to our unitholders and thus will be borne indirectly by our
unitholders.




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





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




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





If
unitholders sell their common units, they will recognize a gain or loss equal to
the difference between the amount realized and their tax basis in those common
units. Because distributions in excess of a unitholder’s allocable share of our
net taxable income decreases the tax basis in the unitholder’s common units, the
amount, if any, of such prior excess distributions with respect to the units
they sell will, in effect, become taxable income to them if they sell such units
at a price greater than their tax basis in those units, even if the price they
receive is less than their original cost. Furthermore, a substantial portion of
the amount realized, whether or not representing gain, may be taxed as ordinary
income due to potential recapture items, including depreciation recapture. In
addition, because the amount realized includes a unitholder’s share of our
nonrecourse liabilities, if a unitholders sells their units, they may incur a
tax liability in excess of the amount of cash they receive from the
sale.




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




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




We
treat each purchaser of our common units as having the same tax benefits without
regard to the actual units purchased. The




28
 Table of Contents




IRS
may challenge this treatment, which could adversely affect the value of the
common units.




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




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




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




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




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




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




We will
be considered to have terminated for federal income tax purposes if there is a
sale or exchange of 50% or more of the total interests in our capital and
profits within a twelve-month period. For purposes of determining whether the
50% threshold has been met, multiple sales of the same interest will be counted
only once. Our termination would, among other things, result in the closing of
our taxable year for all unitholders, which would result in us filing two tax
returns (and our unitholders could receive two Schedules K-1) for one fiscal
year and could result in a deferral of depreciation deductions allowable in
computing our taxable income.  In the case of a unitholder reporting on a
taxable year other than a fiscal year ending December 31, the closing of
our taxable year may also result in more than twelve months of our taxable
income or loss being includable in his taxable income for the year of
termination.  Our termination currently would not affect our classification
as a partnership for federal income tax purposes.  If treated as a new
partnership, we must make new tax election and could be subject to penalties if
we are unable to determine that a termination occurred.




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




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





ITEM 1B.   UNRESOLVED STAFF COMMENTS




None.




ITEM 2.   PROPERTIES


A
description of our properties is included in Part I, Item 1, Business,
and is incorporated herein by reference.
  We
believe that we have satisfactory title to the properties owned and used in our
businesses, subject to liens for taxes not yet




29
 Table of Contents




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




ITEM 3.   LEGAL PROCEEDINGS




Although
we may, from time to time, be involved in litigation and claims arising out of
our operations in the normal course of business, we are not currently a party to
any material legal proceedings. In addition, we are not aware of any legal or
governmental proceedings against us, or contemplated to be brought against us,
under the various environmental protection statutes to which we are
subject.




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




On
September 8, 2006, Asher filed a complaint in Kentucky state court
initiating an action styledAsher Land and Mineral, Ltd. v. Nami Resources Company, LLC, Bell Circuit
Court, Civil Action No. 06-CI-00417. In that action, Asher sought monetary
damages and court-ordered rescission of the leases. Before a responsive pleading
was filed, Asher voluntarily withdrew its complaint and dismissed the case. On
December 15, 2006, Asher filed a new action styledAsher Land and Mineral, Ltd. v.
Nami Resources Company, LLC, Bell Circuit Court, Civil Action
No. 06-CI-00566. In that action, Asher has made the same allegations as in
the prior suit and added a claim for an undetermined amount of punitive damages.
The parties have exchanged limited initial discovery requests.




On
August 29, 2007, Asher filed a motion to add additional defendants to the
action cited above, including Vanguard Natural Resources, LLC, Vanguard Natural
Gas, LLC and Trust Energy Company, LLC. The Company has filed several motions to
be dismissed from this action but to date is still a named defendant in this
case. Since that time, no discovery has been sought from the Company by Asher.
We have retained separate counsel to represent us in this case as it progresses
and intend to continue to vigorously defend the action.




We
received a contract right to receive approximately 99% of the net proceeds from
the sale of production from certain producing oil and gas wells located within
the Asher lease, which accounted for approximately 2.6% of our estimated proved
reserves as of December 31, 2008. We did not receive an assignment of any
working interest in the Asher lease. The Asher lease and the litigation related
thereto were retained by Nami Resources Company, LLC. If the Asher lease is
terminated or if Nami Resources Company, LLC’s rights to production under wells
of which we have contract rights to receive proceeds are adversely affected, we
could lose our contract rights to receive such proceeds or it could be adversely
affected.




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




ITEM 4.
            SUBMISSION
      OF MATTERS TO A VOTE OF SECURITY
HOLDERS




None.




PART II




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




Our
common units are traded on the NYSE Arca, Inc. under the symbol “VNR”. Our
units began trading on October 24, 2007, in connection with our IPO. On
March 5, 2009, there were 12,145,873 common units outstanding and
approximately eleven unitholders, which does not include beneficial owners whose
units are held by a clearing agency, such as a broker or a bank. On
March 5, 2009, the market price for our common units was $8.85 per unit,
resulting in an aggregate market value of units held by non-affiliates of
approximately $78,728,476.  The following table presents the high and low
sales price for our common units during the periods
indicated.




30
 Table of Contents






Common UnitsHigh
                  
                  
                  Low2008Fourth
      Quarter
                  
                  $
                  12.00
                  
                  
                  $
                  4.62Third
      Quarter
                  
                  $
                  16.75
                  
                  
                  $
                  11.70Second
      Quarter
                  
                  $
                  18.55
                  
                  
                  $
                  15.30First
      Quarter
                  
                  $
                  17.25
                  
                  
                  $
                  13.552007Fourth
      Quarter
                  
                  $
                  19.15
                  
                  
                  $
                  14.12




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





October 24, 2007
                      
                      
                      December 31, 2007
                      
                      
                      December 31, 2008Vanguard
      Natural Resources, LLC
                      
                      $
                      100
                      
                      
                      $
                      84.48
                      (1)
                      
                      $
                      35.37
                      (1)Peer
      Group Index
                      
                      $
                      100
                      
                      
                      $
                      90.76
                      
                      
                      $
                      42.75S&P
      500 Index
                      
                      $
                      100
                      
                      
                      $
                      96.87
                      
                      
                      $
                      59.59





(1)
            Based
      on the last reported sale price of VNR units as reported by NYSE
      Arca, Inc. on December 31, 2007 ($16.00) and 2008
      ($5.90).




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




Cash DistributionsPer Unit
                      
                      Record Date
                      Payment Date2008Fourth
      Quarter
                      
                      $
                      0.50
                      
                      January
      30, 2009
                      February
      14, 2009Third
      Quarter
                      
                      $
                      0.50
                      
                      October
      31, 2008
                      November
      14, 2008Second
      Quarter
                      
                      $
                      0.445
                      
                      July
      31, 2008
                      August
      14, 2008First
      Quarter
                      
                      $
                      0.445
                      
                      April
      30, 2008
                      May15,
      2008  31
 Table of Contents
  2007Fourth
      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 liability company agreement requires that, within 45 days after the end
of each quarter, beginning with the quarter ended December 31, 2007, we
distribute all of our available cash to unitholders of record on the applicable
record date. Available cash generally means, for any quarter ending prior to
liquidation:




(a)the
      sum of:





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





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





Equity Compensation
Plans. See Item 12. "Security
Ownership of Certain Beneficial Owners and Management and Related Stockholder
Matters" for information regarding our equity compensation plans as of December
31, 2008.




Unregistered Sale of Equity
Securities and Use of Proceeds.  On July 28, 2008, we completed
the acquisition of certain natural gas and oil properties located in the Dos
Hermanos Field in Webb County, Texas from Segundo Navarro Drilling, Ltd., a
wholly owned subsidiary of the Lewis Energy Group.  As consideration
for the purchase, we paid $30.0 million in cash and issued 1,350,873
unregistered common units, valued at $15.81 per unit.





ITEM 6.   SELECTED FINANCIAL DATA




Set forth
below is our summary of our consolidated financial and operating data for the
periods indicated for Vanguard Natural Resources, LLC and our Predecessor. The
historical financial data for the years ended December 31, 2004, 2005 and
2006 and the balance sheet data as of December 31, 2005 and 2006 have been
derived from the audited financial statements of our Predecessor. Please read
“Item 7, Management’s Discussion and Analysis of Financial Condition and
Results of Operations—Comparability of Our Financial Statements to Our
Predecessor” for the reasons why the historical financial statements of our
Predecessor included in this Annual Report on Form 10-K may not be
comparable to our results of operations.




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


32
 Table of Contents




The
following table presents a non-GAAP financial measure, adjusted EBITDA, which we
use in our business. This measure is not calculated or presented in accordance
with generally accepted accounting principles, or GAAP. We explain this measure
below and reconcile it to the most directly comparable financial measure
calculated and presented in accordance with GAAP in “Non-GAAP Financial
Measure.”
  Year Ended December 31,
      (6) (7)(in thousands,
      except per unit data)Vanguard
                    
                    
                    Vanguard
                      Predecessor2008
                    
                    
                    2007
                    
                    
                    2006
                    
                    
                    2005
                    
                    
                    2004Statement
      of Operations Data:Revenues:Natural gas and oil
      sales
                    
                    $
                    68,850
                    
                    
                    $
                    34,541
                    
                    
                    $
                    38,184
                    
                    
                    $
                    40,299
                    
                    
                    $
                    23,881Gain
      (loss) on commodity cash flow hedges (1)
                    
                    
                    269
                    
                    
                    
                    (702
                    )
                    
                    
                    —
                    
                    
                    
                    —
                    
                    
                    
                    —Gain (loss) on other commodity
      derivative contracts (1)
                    
                    
                    32,477
                    
                    
                    
                    —
                    
                    
                    
                    15,540
                    
                    
                    
                    (28,803
                    )
                    
                    
                    (6,917
                    )Other
                    
                    
                    —
                    
                    
                    
                    —
                    
                    
                    
                    665
                    
                    
                    
                    451
                    
                    
                    
                    29Total
      revenues
                    
                    
                    101,596
                    
                    
                    
                    33,839
                    
                    
                    
                    54,389
                    
                    
                    
                    11,947
                    
                    
                    
                    16,993Costs
      and Expenses:Lease operating
      expenses
                    
                    
                    11,112
                    
                    
                    
                    5,066
                    
                    
                    
                    4,896
                    
                    
                    
                    4,607
                    
                    
                    
                    2,407Depreciation,
      depletion and amortization
                    
                    
                    14,910
                    
                    
                    
                    8,981
                    
                    
                    
                    8,633
                    
                    
                    
                    6,189
                    
                    
                    
                    4,029Impairment of natural gas and
      oil properties
                    
                    
                    58,887
                    
                    
                    
                    —
                    
                    
                    
                    —
                    
                    
                    
                    —
                    
                    
                    
                    —Selling, general and
      administrative
                    
                    
                    6,715
                    (2)
                    
                    
                    3,507
                    (2)
                    
                    
                    5,199
                    
                    
                    
                    5,946
                    
                    
                    
                    3,154Bad
      debt expense
                    
                    
                    —
                    
                    
                    
                    1,007
                    
                    
                    
                    —
                    
                    
                    
                    —
                    
                    
                    
                    —Taxes other than
      income
                    
                    
                    4,965
                    
                    
                    
                    2,054
                    
                    
                    
                    1,774
                    
                    
                    
                    1,249
                    
                    
                    
                    611Total costs and
      expenses
                    
                    
                    96,589
                    
                    
                    
                    20,615
                    
                    
                    
                    20,502
                    
                    
                    
                    17,991
                    
                    
                    
                    10,201Income
      (Loss) from Operations:
                    
                    
                    5,007
                    
                    
                    
                    13,224
                    
                    
                    
                    33,887
                    
                    
                    
                    (6,044
                    )
                    
                    
                    6,792Other
      Income and (Expenses):Interest
      income
                    
                    
                    17
                    
                    
                    
                    62
                    
                    
                    
                    40
                    
                    
                    
                    52
                    
                    
                    
                    7Interest and financing
      expenses
                    
                    
                    (5,491
                    )
                    
                    
                    (8,135
                    )
                    
                    
                    (7,372
                    )
                    
                    
                    (4,566
                    )
                    
                    
                    (1,455
                    )Loss on interest rate
      derivative contracts (3)
                    
                    
                    (3,284
                    )
                    
                    
                    —
                    
                    
                    
                    —
                    
                    
                    
                    —
                    
                    
                    
                    —Loss
      on extinguishment of debt
                    
                    
                    —
                    
                    
                    
                    (2,502
                    )
                    
                    
                    —
                    
                    
                    
                    —
                    
                    
                    
                    —Total other
      expenses
                    
                    
                    (8,758
                    )
                    
                    
                    (10,575
                    )
                    
                    
                    (7,332
                    )
                    
                    
                    (4,514
                    )
                    
                    
                    (1,448
                    )Net
      income (loss)
                    
                    $
                    (3,751
                    )
                    
                    $
                    2,649
                    
                    
                    $
                    26,555
                    
                    
                    $
                    (10,558
                    )
                    
                    $
                    5,344Net
      income (loss) per unit:Common
      and Class B units- basic & diluted (4)
                    
                    $
                    (0.32
                    )
                    
                    $
                    0.39Cash
      Flow Data:Net
      cash provided by operating activities (1)
                    
                    $
                    39,555
                    
                    
                    $
                    1,372
                    
                    
                    $
                    16,087
                    
                    
                    $
                    10,530
                    
                    
                    $
                    9,607Net
      cash used in investing activities
                    
                    
                    (119,540
                    )
                    
                    
                    (26,409
                    )
                    
                    
                    (37,383
                    )
                    
                    
                    (37,068
                    )
                    
                    
                    (19,598
                    )Net
      cash provided by  (used in) financing
      activities
                    
                    
                    76,878
                    
                    
                    
                    26,415
                    
                    
                    
                    19,985
                    
                    
                    
                    25,571
                    
                    
                    
                    (12,721
                    )Other
      Financial Information (unaudited):Adjusted
      EBITDA (5)
                    
                    $
                    48,754
                    
                    
                    $
                    30,395
                    
                    
                    $
                    24,772
                    
                    
                    $
                    18,924
                    
                    
                    $
                    11,812





(1)
            Natural
      gas and oil derivative contracts were used to reduce our exposure to
      changes in natural gas and oil prices. Prior to 2007, they were not
      specifically designated as hedges under Statement of Financial Accounting
      Standards (SFAS) No. 133 “Accounting for Derivatives
      Instruments and Hedging Activities” (“SFAS 133”), thus the
      changes in the fair value of commodity derivative contracts were marked to
      market in our earnings. In 2007, we designated all commodity derivative
      contracts as cash flow hedges; therefore, the changes in fair value
      in 2007 are included in other comprehensive income (loss). In 2008, all
      commodity derivative contracts were either de-designated as cash flow
      hedges or they failed to meet the hedge documentation requirements for
      cash flow hedges. As a result, (a) for the cash flow hedges that were
      settled in 2008, the change in fair value through December 31, 2007 has
      been reclassified to earnings from accumulated other comprehensive loss
      and is classified as gain on commodity cash flow hedges and (b) the
      changes in the fair value of other commodity derivative contracts are
      recorded in earnings and classified as gain on other commodity derivative
      contracts. Unrealized gains (losses) on other commodity derivative
      contracts, which represent non-cash charges, were $39.0 million, $17.7
      million, $(18.8) million and $(1.0) million in 2008, 2006, 2005 and 2004,
      respectively.(2)
            
            Includes
      $3.6 million and $2.1 million of non-cash unit-based compensation expense
      in 2008 and 2007, respectively.           33
 Table of Contents
  (3)
            
            Includes
      $3.2 million in unrealized losses in 2008.(4)
            
            No
      calculation of earnings per unit was made for the Vanguard Predecessor as
      there was a single member interest prior to 2007.(5)
            
            See
      “Non-GAAP Financial Measure” below.(6)
            
            The
      Permian acquisition closed on January 31, 2008 and, as such, only eleven
      months of operations are included in the year ended December 31, 2008 and
      were not included in the results of 2007, 2006, 2005 and
    2004.(7)
            
            The
      south Texas acquisition closed on July 28, 2008 and, as such, only five
      months of operations are included in the year ended December 31, 2008 and
      were not included in the results of 2007, 2006, 2005 and
    2004.








As of December 31,
      (1) (2)(in thousands)Vanguard
                
                
                Vanguard
                  Predecessor2008
                
                
                2007
                
                
                2006
                
                
                2005
                
                
                2004Balance
      Sheet Data:Cash
      and cash equivalents
                
                $
                3
                
                
                $
                3,110
                
                
                $
                1,731
                
                
                $
                3,041
                
                
                $
                4,009Short-term
      derivative assets
                
                
                22,184
                
                
                
                4,017
                
                
                
                —
                
                
                
                —
                
                
                
                —Other
      current assets
                
                
                9,691
                
                
                
                4,826
                
                
                
                20,438
                
                
                
                19,598
                
                
                
                10,033Natural
      gas and oil properties, net of accumulated depreciation, depletion,
      amortization and accretion
                
                
                182,269
                
                
                
                106,983
                
                
                
                104,684
                
                
                
                83,513
                
                
                
                54,761Property,
      plant and equipment, net of accumulated depreciation
                
                
                184
                
                
                
                166
                
                
                
                11,873
                
                
                
                4,104
                
                
                
                1,894Long-term
      derivative assets
                
                
                15,749
                
                
                
                1,330
                
                
                
                —
                
                
                
                —
                
                
                
                —Other
      assets
                
                
                2,482
                
                
                
                10,747
                
                
                
                —
                
                
                
                —
                
                
                
                —Total
      Assets
                
                $
                232,562
                
                
                $
                131,179
                
                
                $
                138,726
                
                
                $
                110,256
                
                
                $
                70,697


Short-term
      derivative liabilities
                  
                  $
                  487
                  
                  
                  $
                  —
                  
                  
                  $
                  2,022
                  
                  
                  $
                  11,527
                  
                  
                  $
                  800Other
      current liabilities
                  
                  
                  7,277
                  
                  
                  
                  5,355
                  
                  
                  
                  11,505
                  
                  
                  
                  12,033
                  
                  
                  
                  6,347Long-term
      debt
                  
                  
                  135,000
                  
                  
                  
                  37,400
                  
                  
                  
                  94,068
                  
                  
                  
                  72,708
                  
                  
                  
                  42,318Long-term
      derivative liabilities
                  
                  
                  2,313
                  
                  
                  
                  5,903
                  
                  
                  
                  —
                  
                  
                  
                  8,243
                  
                  
                  
                  191Other
      long-term liabilities
                  
                  
                  2,134
                  
                  
                  
                  190
                  
                  
                  
                  418
                  
                  
                  
                  212
                  
                  
                  
                  130Members’
      capital
                  
                  
                  85,351
                  
                  
                  
                  82,331
                  
                  
                  
                  30,713
                  
                  
                  
                  5,533
                  
                  
                  
                  20,911Total
      Liabilities and Members’ Capital
                  
                  $
                  232,562
                  
                  
                  $
                  131,179
                  
                  
                  $
                  138,726
                  
                  
                  $
                  110,256
                  
                  
                  $
                  70,697










(1)
            The
      Permian acquisition closed on January 31, 2008 and, as such, only eleven
      months of operations are included in the year ended December 31, 2008 and
      were not included in the results of 2007, 2006, 2005 and
    2004.(2)
            
            The
      south Texas acquisition closed on July 28, 2008 and, as such, only five
      months of operations are included in the year ended December 31, 2008 and
      were not included in the results of 2007, 2006, 2005 and
    2004.








Summary
Reserve and Operating Data




The
following tables show estimated net proved reserves based on a reserve report
prepared by our independent petroleum engineers, NSAI, and certain summary
unaudited information 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 and Analysis of Financial Condition and Results of Operations,” “Item
1—Business—Natural Gas and Oil Data—Proved Reserves” and “—Production and Price
History” included in this Annual report on Form 10-K in evaluating the
material presented below.






34
 Table of Contents




As of
                  December 31,
                  2008Reserve Data:Estimated net proved reserves:Natural
      gas (Bcf)
                
                81.2Crude
      oil (MBbls)
                
                4,547Total
      (Bcfe)
                
                108.5Proved
      developed (Bcfe)
                
                80.9Proved
      undeveloped (Bcfe)
                
                27.6Proved
      developed reserves as % of total proved reserves
                
                75
                %Standardized
      Measure (in millions) (1)
                
                $
                190.1Representative
      Natural Gas and Oil Prices:Natural
      gas—spot Henry Hub per MMBtu
                
                $
                5.71Oil—WTI
      per Bbl
                
                $
                41.00







Year Ended December 31,Vanguard
                
                Vanguard
                  Predecessor2008
                
                
                2007
                
                
                2006Net
      Production:Total
      realized production (MMcfe)
                
                
                5,931
                
                
                
                4,238
                
                
                
                4,378Average
      daily production (Mcfe/day)
                
                
                16,206
                (2)
                
                
                11,610
                
                
                
                11,995Average
      Realized Sales Prices ($ per Mcfe):Average
      sales prices (including hedges)
                
                $
                11.43
                (3)
                
                $
                8.99
                (3)
                
                $
                8.22Average
      sales prices (excluding hedges)
                
                $
                11.61
                
                
                $
                8.15
                
                
                $
                8.72Average
      Unit Costs ($ per Mcfe):Production
      costs
                
                $
                2.71
                
                
                $
                1.68
                
                
                $
                1.52Selling,
      general and administrative expenses
                
                $
                1.13
                (5)
                
                $
                0.83
                (5)
                
                $
                1.19Depreciation,
      depletion, amortization and accretion
                
                $
                2.51
                
                
                $
                2.12
                
                
                $
                1.97













(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 SEC (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,
      amortization and accretion and discounted using an annual discount rate of
      10%. Our Standardized Measure does not include future income tax expenses
      because we are not subject to income taxes and our reserves are owned by
      our subsidiary Vanguard Natural Gas, LLC which is also not subject to
      income taxes. Standardized Measure does not give effect to derivative
      transactions. For a description of our derivative transactions, please
      read “Item 1—Operations—Price Risk Management Activities” and “Item
      7A—Quantitative and Qualitative Disclosures About Market
      Risk.”(2)
            
            Average
      daily production for 2008 calculated based on 366 days including
      production for the Permian Basin and south Texas acquisitions from the
      closing dates of these acquisitions.(3)
            
            Excludes
      amortization of premiums paid and non-cash settlement on derivative
      contracts.(4)
            
            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.(5)
            
            Includes
      $3.6 million ($.60/Mcfe) and $2.1 million ($0.51/Mcfe) of non-cash
      unit-based compensation expense in 2008 and 2007,
      respectively.




Non-GAAP
Financial Measure




Adjusted
      EBITDA






35
 Table of Contents




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




·
            Net
      interest expense, including write-off of deferred financing fees and
      realized gains and losses on interest rate derivative
      contracts;·
            Loss
      on extinguishment of debt;·
            Depreciation,
      depletion and amortization (including accretion of asset retirement
      obligations);·
            Impairment
      of natural gas and oil properties;·
            Bad
      debt expenses;·
            Amortization
      of premiums paid and non-cash settlement on derivative
      contracts;·
            Unrealized
      gains and losses on other commodity and interest rate derivative
      contracts;·
            Change
      in fair value of derivative contracts;·
            Deferred
      tax liabilities;·
            Unit-based
      compensation expense; and·
            Realized
      gains and losses on cancelled
derivatives.





Adjusted
EBITDA is a
significant performance metricused by management as a tool to measure
(prior to the establishment of any cash reserves by our board of directors, debt
service and capital expenditures) the cash distributions we could pay our
unitholders. Specifically, this financial measure indicates to investors whether
or not we are generating cash flow at a level that can sustain or support an
increase in our quarterly distribution rates. Adjusted EBITDA is also used as a
quantitative standard by our management and by external users of our financial
statements such as investors, research analysts and others to assess the
financial performance of our assets without regard to financing methods, capital
structure or historical cost basis; the ability of our assets to generate cash
sufficient to pay interest costs and support our indebtedness; and our operating
performance and return on capital as compared to those of other companies in our
industry.




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




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




Year Ended December 31,(in thousands)Vanguard
                
                
                Vanguard
                  Predecessor2008
                
                
                2007
                
                
                2006
                
                
                2005
                
                
                2004Net
      Income (Loss)
                
                $
                (3,751
                )
                
                $
                2,649
                
                
                $
                26,555
                
                
                $
                (10,558
                )
                
                $
                5,344Plus:Interest expense, including
      realized loss on interest rate derivative contracts
                
                
                5,597
                
                
                
                8,135
                
                
                
                7,372
                
                
                
                4,566
                
                
                
                1,455Loss on extinguishment of
      debt
                
                
                —
                
                
                
                2,502
                
                
                
                —
                
                
                
                —
                
                
                
                —Depreciation, depletion,
      amortization and accretion
                
                
                14,910
                
                
                
                8,981
                
                
                
                8,633
                
                
                
                6,189
                
                
                
                4,029Impairment of natural gas and oil
      properties
                
                
                58,887
                
                
                
                —
                
                
                
                —
                
                
                
                —
                
                
                
                —Bad debt
      expense
                
                
                —
                
                
                
                1,007
                
                
                
                —
                
                
                
                —
                
                
                
                —Amortization of premiums paid and
      non-cash settlement on derivative contracts
                
                
                5,226
                
                
                
                4,274
                
                
                
                —
                
                
                
                —
                
                
                
                —Unrealized (gains) losses on
      other commodity and interest rate derivative contracts (1)
                
                
                (35,852
                )
                
                
                —
                
                
                
                (17,748
                )
                
                
                18,779
                
                
                
                991   36
 Table of Contents
  Deferred tax
      liability
                
                
                177
                
                
                
                —
                
                
                
                —
                
                
                
                —
                
                
                
                —Unit-based compensation
      expense
                
                
                3,577
                
                
                
                2,132
                
                
                
                —
                
                
                
                —
                
                
                
                —Realized loss on cancelled
      derivatives
                
                
                —
                
                
                
                777
                
                
                
                —
                
                
                
                —
                
                
                
                —Less:Interest
    income
                
                
                17
                
                
                
                62
                
                
                
                40
                
                
                
                52
                
                
                
                7Adjusted
      EBITDA
                
                $
                48,754
                
                
                $
                30,395
                
                
                $
                24,772
                
                
                $
                18,924
                
                
                $
                11,812








(1)
            Natural
      gas and oil derivative contracts were used to reduce our exposure to
      changes in natural gas and oil prices. Prior to 2007, they were not
      specifically designated as hedges under FAS 133, thus the changes in
      the fair value of commodity derivative contracts were marked to market in
      our earnings and classified as gain (loss) on other commodity derivative
      contracts. In 2007, we designated all commodity derivative contracts as
      cash flow hedges. In 2008, all commodity derivative contracts were either
      de-designated as cash flow hedges or they failed to meet the hedge
      documentation requirements for cash flow hedges. As a result, the changes
      in the fair value of other commodity derivative contracts are recorded in
      earnings and classified as gain on other commodity derivative contracts.
      The changes in fair value of interest rate derivative contracts in
      recorded in earnings and classified as loss on interest rate derivative
      contracts.







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




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




Overview




We are a
publicly traded limited liability company focused on the acquisition and
development of mature, long-lived natural gas and oil properties in the United
States. Our primary business objective is to generate stable cash flows allowing
us to make quarterly cash distributions to our unitholders and over time to
increase our quarterly cash distributions through the acquisition of new natural
gas and oil properties. As of December 31, 2008, our properties are located
in the southern portion of the Appalachian Basin, primarily in southeast
Kentucky and northeast Tennessee, the Permian Basin, primarily in west Texas and
southeastern New Mexico, and in south Texas.




At
December 31, 2008, we owned working interests in 1,444 gross (958 net)
productive wells. In addition to these productive wells, we own leasehold
acreage allowing us to drill new wells.  As of December 31, 2008, we
had a 40% working interest in approximately 109,500 gross undeveloped acres
surrounding or adjacent to our existing wells located in the Appalachian Basin.
In south Texas, we own working interests ranging from 45-50% in approximately
5,300 undeveloped acres surrounding our existing wells. Approximately 25% or
27.6 Bcfe of our estimated proved reserves were attributable to our working
interests in undeveloped acreage.




Initial
Public Offering




In
October 2007, we completed our IPO of 5.25 million units representing
limited liability interests in VNR at $19.00 per unit for net proceeds of $92.8
million after deducting underwriting discounts and fees of $7.0 million. In
addition, we incurred offering costs of $2.8 million in connection with the IPO
..The proceeds were used to reduce indebtedness under our reserve-based credit
facility by $80.0 million and the balance was used for the payment of accrued
distributions to pre-IPO unitholders and the payment of a deferred swap
obligation.




Permian
Basin Acquisition




On
December 21, 2007, we entered in to a Purchase and Sale Agreement with the
Apache Corporation for the purchase of certain natural gas and oil properties
located in ten separate fields in the Permian Basin of west Texas and
southeastern New Mexico. The




37
 Table of Contents




purchase
price for said assets was $78.3 million with an effective date of
October 1, 2007. We completed this acquisition on January 31, 2008 for
an adjusted purchase price of $73.4 million, subject to customary post-closing
adjustments. The post-closing adjustments reduced the final purchase price to
$71.5 million and included a purchase price adjustment of $6.8 million for the
cash flow from the acquired properties for the period between the effective
date, October 1, 2007, and the final settlement date. This acquisition was
funded with borrowings under our reserve-based credit facility. Through this
acquisition, we acquired working interests in 390 gross wells (67 net wells), 49
of which we operate. With respect to operations, we have established two
district offices, one in Lovington, New Mexico and the other in Christoval,
Texas to manage these assets. Our operating focus will be on maximizing existing
production and looking for complementary acquisitions that we can add to this
operating platform. With this acquisition, based on internal reserve estimates,
we acquired 4.4 million barrels of oil equivalent, 83% of which is oil and 90%
of which is proved developed producing.





South
Texas Acquisition





On July
18, 2008, we entered into a Purchase and Sale Agreement with Segundo Navarro
Drilling, Ltd., a wholly owned subsidiary of the Lewis Energy Group, for the
acquisition of certain natural gas and oil properties located in the Dos
Hermanos Field in Webb County, Texas. The purchase price for said assets was
$53.4 million with an effective date of June 1, 2008. We completed this
acquisition on July 28, 2008 for an adjusted purchase price of $51.4 million,
subject to customary post-closing adjustments to be determined. This acquisition
was funded with $30.0 million of borrowings under our reserve-based credit
facility and through the issuance of 1,350,873 common units of the Company. In
this purchase, we acquired an average of a 98% working interest in 91 producing
wells and an average 47.5% working interest in approximately 4,705 gross acres
with 41 identified proved undeveloped locations. An affiliate of Lewis Energy
Group operates all the properties and is contractually obligated to drill seven
wells each year from 2009 through 2011 unless mutually agreed not to do so.
Based on internal reserve estimates, we acquired 20 Bcfe of proved reserves, 98%
of which is natural gas and 65% of which is proved developed producing. Upon
closing this transaction, we assumed natural gas swaps and collars based on
Houston Ship Channel pricing for approximately 85% of the estimated gas
production from existing producing wells for the period beginning July 2008
through December 2011 which had a fair value of $3.6 million on July 28,
2008.




Our
Relationship with Vinland




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




Restructuring
Plan




Prior to
the separation, our Predecessor owned all of the assets in Appalachia that are
currently owned by us and Vinland. As part of the separation of our operating
company and Vinland, effective January 5, 2007, we conveyed to Vinland 60%
of our Predecessor’s working interest in the known producing horizons in
approximately 95,000 gross undeveloped acres in the AMI, 100% of our
Predecessor’s interest in an additional 125,000 undeveloped acres and certain
coalbed methane rights located in the Appalachian Basin, the rights to any
natural gas and oil located on our acreage at depths above and 100 feet below
our known producing horizons, all of our gathering and compression assets and
all employees except, our President and Chief Executive Officer and our
Executive Vice President and Chief Financial Officer. We retained all of our
Predecessor’s proved producing wells and associated reserves. We also retained
40% of our Predecessor’s working interest in the known producing horizons in
approximately 95,000 gross undeveloped acres in the AMI and a contract right to
receive approximately 99% of the net proceeds, after deducting royalties paid to
other parties, severance taxes, third-party transportation costs, costs incurred
in the operation of wells and overhead costs, from the sale of production from
certain producing natural gas and oil wells, which accounted for approximately
2.6% of our estimated proved reserves as of December 31, 2008. In addition,
we changed the name of our operating company from Nami Holding Company, LLC to
Vanguard Natural Gas, LLC. Collectively, we refer to these events as the
“Restructuring.”






38
 Table of Contents





Private
      Offering





In
April 2007, we completed a private equity offering pursuant to which we
issued 2,290,000units to certain private
investors, which we collectively refer to as the Private Investors, for $41.2
million. We used the net proceeds of this private equity offering to make a
distribution to Majeed S. Nami, VNR’s largest unitholder, who used a portion of
these funds to capitalize Vinland and also paid us $3.9 million to reduce
outstanding accounts receivable from Vinland. We then used the $3.9 million
to repay borrowings and interest under our reserve-based credit facility, and
for general limited liability company purposes. Under the terms of the private
offering, all outstanding units accrued distributions at $1.75 annually from the
closing of the private offering to September 30, 2007 and then
distributions payable to the Private Investors only increased to $2.40 until the
completion of the IPO at which time all accrued distributions totaling $5.6
million were paid.




Reserve-Based
Credit Facility





On
January 3, 2007, we entered into a reserve-based credit facility which is
available for our general limited liability company purposes, including, without
limitation, capital expenditures and acquisitions. Our obligations under the
reserve-based credit facility are secured by substantially all of our assets.
Our initial borrowing base under the reserve-based credit facility was set at
$115.5 million. However, the borrowing base was subject to $1.0 million
reductions per month starting on July 1, 2007 through November 1,
2007, which resulted in a borrowing base of $110.5 million as reaffirmed in
November 2007 pursuant to a semi-annual borrowing base redetermination. We
applied $80.0 million of our net proceeds from our IPO in October 2007 to
reduce our indebtedness under our reserve-based credit facility. In February
2008, our reserve-based credit facility was amended and restated to extend the
maturity from January 3, 2011 to March 31, 2011, increase the maximum facility
amount from $200.0 million to $400.0 million, increase our borrowing base from
$110.5 million to $150.0 million and add two additional financial institutions
as lenders, Wachovia Bank, N.A. and The Bank of Nova Scotia. In October 2008,
our borrowing base was set at $175.0 million. Our next borrowing base
redetermination is scheduled for April 2009 utilizing our December 31, 2008
reserve report. As a result of lower commodity prices, it is likely that we will
be subject to a decrease in our borrowing base at our April 2009
redetermination.  Until the redetermination occurs, the amount of the
potential reduction is uncertain but based on preliminary discussions with our
lead bank the expected reduction would not be material to the borrowing base as
a whole and would not inhibit our ability to make distributions to our
unitholders.





Additional
borrowings under our reserve-based credit facility were made in January 2008
pursuant to the acquisition of natural gas and oil properties in the Permian
Basin, and in July 2008 an additional $30.0 million was borrowed to fund a
portion of the cash consideration paid in the south Texas acquisition. In May
2008, our reserve-based credit facility was amended in response to a potential
acquisition that ultimately did not occur. As a result, none of the provisions
included in this amendment went into effect. In October 2008, we amended our
reserve-based credit facility which set our borrowing base under the facility at
$175.0 million pursuant to our semi-annual redetermination and added a new
lender, Compass Bank. As a result, indebtedness under the reserve-based credit
facility totaled $135.0 million at December 31, 2008 and the applicable margins
and the utilization percentages on our borrowing base utilization grid were
changed to reflect the following:






Borrowing
      Base Utilization GridBorrowing
      Base Utilization Percentage
                          
                          <33%
                          
                          
                          >33%
      <66%
                          
                          
                          >66% <85%
                          
                          
                          >85%Eurodollar
      Loans
                          
                          
                          1.500
                          %
                          
                          
                          1.750
                          %
                          
                          
                          2.000
                          %
                          
                          
                          2.125
                          %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
                          %


In
February 2009, a third amendment was entered into which amended covenants to
allow the Company to repurchase up to $5.0 million of our own
units.





Outlook




Our
revenue, cash flow from operations and future growth depend substantially on
factors beyond our control, such as access to capital, economic, political and
regulatory developments, and competition from other sources of energy. Multiple
events during 2008 involving numerous financial institutions have effectively
restricted current liquidity within the capital markets throughout the United
States and around the world. Despite efforts by treasury and banking regulators
in the United States, Europe and other nations around the world to provide
liquidity to the financial sector, capital markets currently remain constrained.
We expect that our ability to raise debt and equity at prices that are similar
to offerings in recent years to be limited as long as the capital markets remain
constrained.





39
 Table of Contents




During
2008, our unit price closed at a high of $18.41 on May 20, 2008 and declined to
a closing low of $4.72 on December 23, 2008, which is the lowest our unit price
has closed at since our initial public offering. Since that date our unit price
has partially recovered to a level of $8.85 on March 5, 2009. We intend to move
forward with our development drilling program when market conditions allow for
an adequate return on the drilling investment and only when we have sufficient
liquidity to do so. Maintaining adequate liquidity may involve the issuance of
debt and equity at less attractive terms, could involve the sale of non-core
assets, could require reductions in our capital spending, and could require a
reduction in our distribution. In the near-term we will focus on maximizing
returns on existing assets by managing our costs and selectively deploying
capital to improve existing production.





Natural
gas and oil prices historically have been volatile and may fluctuate widely in
the future. Sustained periods of low prices for natural gas or oil could
materially and adversely affect our financial position, our results of
operations, the quantities of natural gas and oil reserves that we can
economically produce and our access to capital. As required by our reserve-based
credit facility, we have mitigated this volatility for the years 2007 through
2011 by implementing a hedging program on a portion of our total anticipated
production during this time frame.




We face
the challenge of natural gas and oil production declines. As a given well’s
initial reservoir pressures are depleted, natural gas and oil production
decreases, thus reducing our total reserves. We attempt to overcome this natural
decline both by drilling on our properties and acquiring additional reserves. We
will maintain our focus on controlling costs to add reserves through drilling
and acquisitions, as well as controlling the corresponding costs necessary to
produce such reserves. Our ability to add reserves through drilling is dependent
on our capital resources and can be limited by many factors, including the
ability to timely obtain drilling permits and regulatory approvals and voluntary
reductions in capital spending in a low commodity price environment. Any delays
in drilling, completion or connection to gathering lines of our new wells will
negatively impact the rate of our production, which may have an adverse effect
on our revenues and as a result, cash available for distribution. In accordance
with our business plan, we intend to invest the capital necessary to maintain
our production at existing levels over the long-term provided that it is
economical to do so based on the commodity price environment. However, we cannot
be certain that we will be able to issue our debt and equity securities on
favorable terms, or at all, and we may be unable to refinance our reserve-based
credit facility when it expires. Additionally, due to the significant decline in
commodity prices, our borrowing base under our reserve-based credit facility may
be re-determined such that it will not provide for the working capital necessary
to fund our capital spending program and could affect our ability to make
distributions.




Comparability
      of Our Financial Statements to Our
Predecessor





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




·
            
            On
      April 18, 2007, but effective January 5, 2007, we conveyed to Vinland 60%
      of our Predecessor’s working interest in the known producing horizons in
      approximately 95,000 gross undeveloped acres in the AMI, 100% of our
      Predecessor’s interest in an additional 125,000 undeveloped acres and
      certain coalbed methane rights located in the Appalachian Basin, the
      rights to any natural gas and oil located on our acreage at depths above
      and 100 feet below our known producing horizons 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.·
            
            On
      April 18, 2007, but effective January 5, 2007, we entered into a
      management services agreement and a gathering and compression agreement
      with Vinland which fixed a portion of our production costs for wells owned
      in the area of mutual interest.·
            
            Our
      Predecessor did not account for its derivative instruments as cash flow
      hedges under SFAS 133. 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. In 2008, unrealized gains and losses were recorded
      in earnings as all commodity and interest rate derivative contracts were
      either de-designated as cash flow hedges or they failed to meet the hedge
      documentation requirements for cash flow
hedges.




Results
      of Operations





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






Year Ended December 31,
      (a) (b)(in
      thousands)Vanguard
                  
                  
                  Vanguard
      Predecessor2008
                  
                  
                  2007
                  
                  
                  2006Revenues:Gas
      sales
                  
                  $
                  44,920
                  
                  
                  $
                  32,517
                  
                  
                  $
                  36,306Oil
      sales
                  
                  
                  23,930
                  
                  
                  
                  2,024
                  
                  
                  
                  1,878Natural
      gas and oil sales
                  
                  
                  68,850
                  
                  
                  
                  34,541
                  
                  
                  
                  38,184Gain
      (loss) on commodity cash flow hedges
                  
                  
                  269
                  
                  
                  
                  (702
                  )
                  
                  
                  —Gain
      on other commodity derivative contracts
                  
                  
                  32,477
                  
                  
                  
                  —
                  
                  
                  
                  15,540


40
 Table of Contents
 Other
              
              
              —
              
              
              
              —
              
              
              
              665Total
      revenues
              
              $
              101,596
              
              
              $
              33,839
              
              
              $
              54,389Costs
      and expenses:Lease
      operating expenses
              
              $
              11,112
              
              
              $
              5,066
              
              
              $
              4,896Depreciation,
      depletion, amortization and accretion
              
              
              14,910
              
              
              
              8,981
              
              
              
              8,633Impairment
      of natural gas and oil properties
              
              
              58,887
              
              
              
              —
              
              
              
              —Selling,
      general and administrative expenses
              
              
              6,715
              
              
              
              3,507
              
              
              
              5,199Bad
      debt expense
              
              
              —
              
              
              
              1,007
              
              
              
              —Production
      and other taxes
              
              
              4,965
              
              
              
              2,054
              
              
              
              1,774Total
      costs and expenses
              
              $
              96,589
              
              
              $
              20,615
              
              
              $
              20,502Other
      expenses:Interest
      expense, net
              
              $
              (5,474
              )
              
              $
              (8,073
              )
              
              $
              (7,332
              )Loss
      on interest rate derivative contracts
              
              
              (3,284
              )
              
              
              —
              
              
              
              —Loss
      on extinguishment of debt
              
              
              —
              
              
              
              (2,502
              )
              
              
              —




(a) 
      The Permian acquisition
      closed on January 31, 2008 and,as such,onlyelevenmonths of operations are
      included in theyearendedDecember31, 2008and were not included in the
      results of 2007 and 2006.(b) 
      Thesouth Texas acquisition closed on
      July 28, 2008 and,as such,onlyfivemonths of operations are included
      in theyearendedDecember31, 2008and were not included in the
      results of 2007 and 2006.





Year
Ended December 31, 2008 Compared to Year Ended December 31, 2007





Revenues





Natural
gas and oil sales increased $34.3 million to $68.8 million during the year ended
December 31, 2008 as compared to the same period in 2007. The key revenue
measurements were as follows:


Year Ended
                                                December
      31,
                                              
                                              Percentage
                                                Increase
                                                (Decrease)2008
                                              
                                              2007Net
      Natural Gas Production:Appalachian
      gas (MMcf)
                                              
                                              
                                              3,578
                                              
                                              4,044
                                              
                                              (12)
                                              %Permian
      gas (MMcf)
                                              
                                              
                                              218
                                              (a)
                                              —
                                              
                                              N/ASouth
      Texas gas (MMcf)
                                              
                                              
                                              566
                                              (b)
                                              —
                                              
                                              N/ATotal
      natural gas production (MMcf)
                                              
                                              
                                              4,362
                                              
                                              4,044
                                              
                                              8
                                              %Average
      Appalachian daily gas production (Mcf/day)
                                              
                                              
                                              9,777
                                              
                                              11,080
                                              
                                              (12)
                                              %Average
      Permian daily gas production (Mcf/day)
                                              
                                              
                                              650
                                              (a)
                                              —
                                              
                                              N/AAverage
      south Texas daily gas production (Mcf/day)
                                              
                                              
                                              3,602
                                              (b)
                                              —
                                              
                                              N/AAverage
      Vanguard daily gas production (Mcf/day)
                                              
                                              
                                              14,029
                                              
                                              11,080Average
      Natural Gas Sales Price per Mcf:Net
      realized gas price, including hedges
                                              
                                              
                                              $10.40
                                              (c)
                                              $8.92
                                              (c)
                                              17
                                              %Net
      realized gas price, excluding hedges
                                              
                                              
                                              $10.30
                                              
                                              $8.04
                                              
                                              28
                                              %Net
      Oil Production:Appalachian
      oil (Bbls)
                                              
                                              
                                              48,977
                                              
                                              30,629
                                              
                                              60
                                              %Permian
      oil (Bbls)
                                              
                                              
                                              212,599
                                              (a)
                                              —
                                              
                                              N/ATotal
      oil (Bbls)
                                              
                                              
                                              261,576
                                              
                                              30,629Average
      Appalachian daily oil production (Bbls/day)
                                              
                                              
                                              134
                                              
                                              84
                                              
                                              60
                                              %Average
      Permian daily oil production (Bbls/day)
                                              
                                              
                                              635
                                              (a)
                                              —
                                              
                                              N/AAverageVanguard daily oil production
      (Bbls/day)
                                              
                                              
                                              769
                                              
                                              84Average
      Oil Sales Price per Bbl:Net
      realized oil price, including hedges
                                              
                                              
                                              $85.69
                                              
                                              $66.08
                                              
                                              30
                                              %Net
      realized oil price, excluding hedges
                                              
                                              
                                              $91.48
                                              
                                              $66.08
                                              
                                              38
                                              %





41
 Table of Contents





(a)
                The
      Permian acquisition closed on January 31, 2008 and, as such, only eleven
      months of operations are included in the year ended December 31, 2008
      and were not included in the operations of 2007.(b)
                The
      south Texas acquisition closed on July 28, 2008 and, as such, only five
      months of operations are included in the year ended December 31, 2008 and
      were not included in the operations of 2007.(c)
                Excludes
      amortization of premiums paid and non-cash settlements on derivative
      contracts.





The
increase in natural gas and oil sales was due primarily to the impact of the
Permian Basin acquisition completed on January 31, 2008, the south Texas
acquisition completed on July 28, 2008 and increases in commodity prices during
the first three quarters of 2008. Production from the Permian Basin and
south Texas acquisitions contributed $25.8 million of natural gas and oil sales
for the year ended December 31, 2008. In Appalachia, a 12% decline in natural
gas production was partially offset by a 60% increase in oil production for a
net production decline of 9% on an Mcfe basis. The 60% increase in oil
production was primarily due to a greater focus on the completion of oil zones
as prices increased which conversely affected the amount of natural gas
produced. However, the negative impact of the natural gas production decline was
offset by a 28% increase in the average realized natural gas sales price
received (excluding hedges) and a 38% increase in the average realized oil price
(excluding hedges).


Hedging
and Price Risk Management Activities





During
the year ended December 31, 2008, the Company recognized $0.3 million
and $32.5 million related to gains on commodity cash flow hedges and gains on
other commodity derivative contracts, respectively. These amounts relate to
derivative contracts that the Company entered into in order to mitigate
commodity price exposure on a portion of our expected production.  On
November 10, 2008, the Company concluded that since January 1, 2008 the
contemporaneous formal documentation it had prepared to support its initial
hedge designations and subsequent assessments for ineffectiveness in connection
with the Company’s natural gas and oil hedging program in 2008 had not met the
technical requirements to qualify for cash flow hedge accounting treatment in
accordance with SFAS 133 and it discontinued hedge accounting effective January
1, 2008. The gain on commodity cash flow hedges relates to the amount that
settled in 2008 and has been reclassified to earnings from accumulated other
comprehensive loss. The gain on other commodity derivative contracts relates to
the change in fair value of derivative contracts no longer accounted for under
cash flow hedge accounting.





Costs
and Expenses




Production
costs consist of the lease operating expenses and production and other taxes
(severance and ad valorem taxes). Lease operating expenses include third-party
transportation costs, gathering and compression fees, field personnel, and other
customary charges. Lease operating expenses in Appalachia also include a $60 per
month per well administrative charge pursuant to a management services agreement
with Vinland, a $0.25 per Mcf and $0.55 per Mcf gathering and compression charge
for production from wells drilled pre and post January 1, 2007, respectively,
paid to Vinland pursuant to a gathering and compression agreement with Vinland.
Lease operating expenses increased by $6.0 million to $11.1 million for the year
ended December 31, 2008 as compared to the year months ended December 31, 2007
of which $4.8 million related to the Permian Basin and south Texas acquisitions.
Severance taxes are a function of volumes and revenues generated from
production. Ad valorem taxes vary by state/county and are based on the value of
our reserves. Production and other taxes increased by $2.9 million for the year
ended December 31, 2008 as compared to the same period in 2007 of which $2.0
million related to the Permian Basin and south Texas acquisitions, and the
remaining increase is attributable to higher severance taxes resulting from
increased revenues in Appalachia.




Depreciation,
depletion, amortization and accretion increased to approximately $14.9 million
for the year ended December 31, 2008 from approximately $9.0 million for the
year ended December 31, 2007 due primarily to the additional depletion recorded
on the oil and gas properties acquired in the Permian Basin and south Texas
acquisitions.





An
impairment of natural gas and oil properties in the amount of $58.9 million was
recognized during the year ended December 31, 2008 as the unamortized cost of
natural gas and oil properties exceeded the sum of the estimated future net
revenues from proved properties using period-end prices, discounted at 10% and
the lower of cost or fair value of unproved properties as a result of a
decline in natural gas and oil prices at the measurement date. The impairment
calculation did not consider the positive impact of our commodity derivative
positions as generally accepted accounting principles only allows the inclusion
of derivatives designated as cash flow hedges.




Selling,
general and administrative expenses include the costs of our administrative
employees and executive officers, related benefits, office leases, professional
fees and other costs not directly associated with field operations. These
expenses for the year ended December 31, 2008 increased $3.2 million as compared
to the year ended December 31, 2007. For the years ended December 31, 2008 and
2007 these expenses included a $3.6 million and $2.1million non-cash
compensation charge related to the grant of restricted




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Class B
units to officers and an employee, the grant of unit options to management, and
the grant of common units to board members during 2007 and 2008. The remaining
increase of $1.7 million during the year ended December 31, 2008 as compared to
the same period in 2007 is principally due to incremental costs associated with
being a public company.




Interest
expense declined to $5.5 million for the year ended December 31, 2008 compared
to $8.1 million for the year ended December 31, 2007 primarily due to lower
interest rates which more than offset the higher average outstanding debt for
the year ended December 31, 2008. All of our Predecessor’s outstanding debt was
repaid with borrowings under our reserve-based credit facility in January 2007,
including an early prepayment penalty of $2.5 million.





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




Revenues




Natural
gas and oil sales decreased to approximately $34.5 million for the year ended
December 31, 2007 from approximately $38.2 million for the year ended
December 31, 2006. The key revenue measurements were as
follows:






Year Ended
                        December
      31,
                      
                      Percentage
                        Increase
                        (Decrease)Vanguard
                        2007
                      
                      Vanguard
      Predecessor
                        2006Total
      natural gas production (MMcf)
                      
                      
                      4,044
                      
                      4,182
                      
                      
                      (3)
                      %Average
      Vanguard daily gas production (Mcf/day)
                      
                      
                      11,080
                      
                      11,457
                      
                      
                      (3)
                      %Average
      Natural Gas Sales Price per Mcf:Net
      realized gas price, including hedges
                      
                      
                      $8.92
                      (a)
                      $8.00
                      
                      
                      12
                      %Net
      realized gas price, excluding hedges
                      
                      
                      $8.04
                      
                      $8.68
                      
                      
                      (7)
                      %Total
      oil production (Bbls)
                      
                      
                      30,629
                      
                      32,718
                      
                      
                      (6)
                      %AverageVanguard daily oil production
      (Bbls/day)
                      
                      
                      84
                      
                      90
                      
                      
                      (6)
                      %Average
      Oil Sales Price per Bbl, including and excluding hedges
                      
                      
                      $66.08
                      
                      $57.40
                      
                      
                      15
                      %







(a)
            Excludes
      amortization of premiums paid and non-cash settlements on derivative
      contracts.





The
decrease in natural gas and oil sales was primarily due to the 3% decrease in
natural gas production and the 6% decrease in oil production. Additionally,
contributing to the decrease in natural gas and oil sales was the 7% decrease in
the average realized gas price during the year ended December 31, 2007 over
December 31, 2006. However, the negative impact of the production decline
was offset by a 15% increase in the average realized oil price. The
decrease in production can be attributed to our drilling 83 wells during the
2007 as compared to the Predecessor drilling 100 wells in the same period in
2006.




Hedging
and Price Risk Management Activities




During
the year ended December 31, 2007, we hedged approximately 88% of our
natural gas production, which resulted in reported revenues that were
approximately $0.7 million lower than we would have achieved at unhedged prices.
However, the actual cash impact of the hedges increased realizations by $4.3
million for the period after excluding the premiums paid on the settled
derivatives. In addition, in January 2007, we terminated existing natural
gas swaps at a cost of approximately $2.8 million which resulted in an
additional realized loss on derivative contracts of approximately $0.8 million
during the year ended December 31, 2007. During the year ended
December 31, 2006, our Predecessor hedged approximately 53% of our natural
gas production, which resulted in revenues that were approximately $2.2 million
lower than our Predecessor would have achieved at unhedged prices. The
derivative contracts entered into in 2006 were not specifically designated as
hedges under SFAS 133 and therefore did not qualify for hedge accounting
treatment. As a result, the change in the fair value of these natural gas
derivative contracts was marked to market in earnings each period in 2006 and
resulted in a $17.7 million non-cash gain for the year ended December 31,
2006.




Costs
and Expenses




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Production
costs consist of the lease operating expenses and production and other
taxes (severance and ad valorem taxes). Lease operating expenses includes
third-party transportation costs, operating and maintenance costs associated
with our gathering systems (which were conveyed to Vinland in connection with
the Restructuring) and other customary charges. As a result of the
Restructuring, lease operating expenses for the year ended December 31,
2007 includes third-party transportation costs, a $60 per month per well
administrative charge pursuant to a management services agreement with Vinland,
a $0.25 per Mcf and $0.55 per Mcf gathering and compression charge for
production from wells drilled pre and post January 5, 2007, respectively,
paid to Vinland pursuant to a gathering and compression agreement with Vinland,
as well as other customary charges. Lease operating expenses increased 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 due primarily
to amounts paid to Vinland under the management services agreement and gathering
and compression agreement being comparable to our actual costs incurred for the
same period in 2006. On a per Mcfe basis, lease operating expenses increased by
7% to $1.20 for the year ended December 31, 2007 compared to $1.12 for the
same period in 2006. Severance taxes are a function of volumes and revenues
generated from production. Ad valorem taxes vary by state and county and are
based on the value of our reserves. Production and other taxes increased $0.3
million to $2.1 million or 20% on a per Mcfe basis, for the 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 of severance
taxes in 2006, which was charged to expense in the first quarter of
2007.




Depreciation,
depletion, amortization and accretion 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 the Restructuring effective January 2007. This
result occurred due to the conveyance of long-lived depreciable assets which
generated little associated depreciation and the conveyed value of the 60%
interest in proved undeveloped properties 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 upward revisions of future drilling costs in the
2007 reserve report which increased the full cost pool to be
depleted.




Selling,
general and administrative expenses include the cost of our employees and
executive officers, related benefits, office leases, professional fees and other
costs associated with being a public company not directly resulting from field
operations. 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 of the employees, except two of its officers to Vinland. The
decrease in selling, general and administrative expenses during the year ended
December 31, 2007 as compared to 2006 was offset by two principal factors.
First, our Predecessor capitalized $3.9 million of internal costs under the full
cost method 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-cash compensation charge related to the grant of Class B
units to management, an employee and a board member in April, August and
October 2007.




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




Interest
and financing expenses 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 associated with drilling additional wells and rising interest rates. In
addition, our interest rates during 2007 were directly affected by the provision
in our credit facility which increased our rates by 1% on LIBOR loans effective
July 1, 2007 until we completed our IPO in October 2007.





Critical
      Accounting Policies and Estimates





The
discussion and analysis of our financial condition and results of operations are
based upon the consolidated financial statements, which have been prepared in
accordance with accounting principles generally accepted in the United States.
The preparation of these financial statements requires us to make estimates and
assumptions that affect the reported amounts of assets, liabilities, revenues
and expenses, and related disclosure of contingent assets and liabilities.
Certain accounting policies involve judgments and uncertainties to such an
extent that there is reasonable likelihood that materially different amounts
could have been reported under different conditions, or if different assumptions
had been used. We evaluate our estimates and assumptions on a regular basis. We
base our estimates on historical experience and various other assumptions that
are believed to be reasonable under the circumstances, the results of which form
the basis for making judgments about the carrying values of assets and
liabilities that are not readily apparent from other sources. Actual results may
differ from these estimates and assumptions used in preparation of our financial
statements. Below, we have provided expanded discussion of our more significant
accounting policies, estimates and judgments. We have discussed the development,
selection and disclosure of each of these with our audit committee. We believe
these accounting policies reflect our more significant estimates and assumptions
used in preparation of our financial statements. Please readNote
1  to the Notes to the Consolidated Financial Statements
included in item 8 of this Annual Report on Form 10-K for a discussion of
additional accounting policies and estimates made by management.




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 Table of Contents




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





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




We have
elected to use the full-cost method to account for our investment in natural gas
and oil properties. Under this method, we capitalize all acquisition,
exploration and development costs for the purpose of finding natural gas and oil
reserves, including salaries, benefits and other internal costs directly related
to these finding activities. For the years ended December 31, 2008 and
2007, there were no internal costs capitalized. For the year ended December 31,
2006 such internal costs capitalized totaled $3.9 million. Although some of
these costs will ultimately result in no additional reserves, we expect the
benefits of successful wells to more than offset the costs of any unsuccessful
ones. In addition, gains or losses on the sale or other disposition of natural
gas and oil


properties
are not recognized unless the gain or loss would significantly alter the
relationship between capitalized costs and proved reserves. Our results of
operations would have been different had we used the successful-efforts method
for our natural gas and oil investments. Generally, the application of the
full-cost method of accounting results in higher capitalized costs and higher
depletion rates compared to similar companies applying the successful-efforts
method of accounting.




Full-Cost
      Ceiling Test





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




The
calculation of the Ceiling Test and the provision for depletion and amortization
are based on estimates of proved reserves. There are numerous uncertainties
inherent in estimating quantities of proved reserves and in projecting the
future rates of production, timing, and plan of development as more fully
discussed in “Natural Gas and Oil Reserve Quantities” below. Due to the
imprecision in estimating natural gas and oil reserves as well as the potential
volatility in natural gas and oil prices and their effect on the carrying value
of our proved natural gas and oil reserves, there can be no assurance that
additional Ceiling Test write downs in the future will not be required as a
result of factors that may negatively affect the present value of proved natural
gas and oil properties. These factors include declining natural gas and oil
prices, downward revisions in estimated proved natural gas and oil reserve
quantities and unsuccessful drilling activities. We recorded a non-cash ceiling
test impairment of natural gas and oil properties for the year ended December
31, 2008 of $58.9 million as a result of a decline in natural gas and oil prices
at the measurement date.  This impairment was calculated based on
prices of $5.71 per MMBtu for natural gas and $41.00 per barrel of crude
oil.  No ceiling test impairment was required during 2007 or
2006.






Asset
      Retirement Obligation


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




Natural
      Gas and Oil Reserve Quantities





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




Reserves
and their relation to estimated future net cash flows impact our depletion and
impairment calculations. As a result, adjustments to depletion and impairment
are made concurrently with changes to reserve estimates. We prepare our reserve
estimates, and the projected cash flows derived from these reserve estimates, in
accordance with SEC guidelines. The independent engineering




45
 Table of Contents




firm
described above adheres to the same guidelines when preparing their reserve
reports. The accuracy of our reserve estimates is a function of many factors
including the following: the quality and quantity of available data, the
interpretation of that data, the accuracy of various mandated economic
assumptions and the judgments of the individuals preparing the
estimates.




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




Revenue
      Recognition





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




Gas
imbalances occur when we sell more or less than our entitled ownership
percentage of total gas production. Any amount received in excess of our share
is treated as a liability. If we receive less than our entitled share the
underproduction is recorded as a receivable. We did not have any significant gas
imbalance positions at December 31, 2008 or 2007.




Price
      Risk Management Activities





We
periodically use derivative financial instruments to achieve a more predictable
cash flow from our natural gas and oil production by reducing our exposure to
price fluctuations. Currently, these derivative financial instruments include
fixed-price swaps, collars and put options. The derivative instruments we
established in 2007 were designated as hedges under SFAS 133. In connection with
preparing its quarterly report for third quarter 2008 and discussion with BDO
Seidman, LLP, the Company’s new independent registered public accounting firm,
management of the Company and the Audit Committee of its Board of Directors
concluded that the contemporaneous formal documentation it had prepared to
support its initial hedge designations and subsequent assessments for
ineffectiveness in connection with the Company’s natural gas and oil hedging
program in 2008 did not meet the technical requirements to qualify for cash flow
hedge accounting treatment in accordance with SFAS 133.  The primary
reasons for this determination were that the formal hedge documentation lacked
specificity of the hedged cash flow and the quantitative subsequent assessments
for ineffectiveness were insufficient.  Therefore, the cash flow
designations failed to meet hedge documentation requirements for cash flow hedge
accounting treatment. In addition, the natural gas derivative swap contracts
entered into in 2007 were de-designated as cash flow hedges in the first quarter
of 2008 due to an overhedged position in natural gas which made them
ineffective.





Under
SFAS 133, the fair value of hedge contracts is recognized in the Consolidated
Balance Sheets as an asset or liability, and the change in fair value of the
hedge contracts are reflected in earnings.  If the hedge contracts
qualify for hedge accounting treatment, the fair value of the hedge contract is
recorded in “accumulated other comprehensive income,” and changes in the fair
value do not affect net income until the contract is settled.  If the
hedge contract does not qualify for hedge accounting treatment, the change in
the fair value of the hedge contract is reflected in earnings during the period
as gain or loss on other commodity derivatives.  Under the cash flow
hedge accounting treatment used by the Company in 2007, the fair values of the
hedge contracts were recognized in the consolidated balance sheets with the
resulting unrealized gain or loss recorded initially in accumulated other
comprehensive income and later reclassified through earnings when the hedged
production affected earnings.  As a result of the determination that
the documentation failed to meet cash flow hedge accounting treatment, the
unrealized gain or loss on other commodity derivatives was recorded in the
consolidated statements of operations as a component of revenues in 2008. In
addition, the net derivative loss at December 31, 2007 related to the
de-designated natural gas derivative contracts entered into in 2007 is reported
in accumulated other comprehensive income until the month in which the
transactions settle.





Our
Predecessor did not specifically designate the derivative instruments
established in 2006 as hedges under SFAS 133, even though they protected our
Predecessor from changes in commodity prices. Therefore, the mark to market of
these instruments was recorded in current earnings as a component of total
revenues. Further, these mark to market amounts represent non-cash charges. Had
no hedges been in place, our Predecessor would have received additional revenue
of $2.2 million during 2006. In January 2007, we terminated existing hedges
at a cost of approximately $2.8 million, of which $0.8 million is reflected as a
realized loss on commodity cash flow hedges on the statement of operations for
the year ended December 31, 2007.




Stock
      Based Compensation







46
 Table of Contents


We
account for Stock Based Compensation pursuant to SFAS No. 123(R)—Share-Based Payment(“SFAS
123(R)”). SFAS 123(R) requires an entity to recognize the grant-date
fair-value of stock options and other equity-based compensation issued to
employees in the income statement and eliminates the alternative to use the
intrinsic value method of accounting that was provided in SFAS 123, which
generally resulted in no compensation expense recorded in the financial
statements related to the issuance of equity awards to employees. It establishes
fair value as the measurement objective in accounting for share-based payment
arrangements and requires all companies to apply a fair-value-based measurement
method in accounting for generally all share-based payment transactions with
employees. On March 29, 2005, the SEC staff issued SAB No. 107,
Share-Based Payment, to express the views of the staff regarding the interaction
between SFAS 123(R) and certain SEC rules and regulations and to
provide the staff’s views regarding the valuation of share-based payment
arrangements for public companies.




In April
2007, the sole member at that time reserved 460,000 restricted Class B units in
VNR for issuance to employees. Certain members of management were granted
365,000 restricted Class B units in VNR in April 2007, which vest two years from
the date of grant. In addition, another 55,000 restricted VNR Class B units were
issued in August 2007 to two other employees that were hired in April and May of
2007, which will vest after three years. The remaining 40,000 restricted Class B
units are available to be awarded to new employees or members of our board of
directors as they are retained. In October 2007 and February 2008, four board
members were granted 5,000 common units each of which will vest after one year.
Additionally, in October 2007, two officers were granted options to purchase an
aggregate of 175,000 units under our long-term incentive plan with an exercise
price equal to the initial public offering price of $19.00 which vested
immediately upon being granted and had a fair value of $0.1 million on the date
of grant.





Furthermore,
on March 27, 2008, phantom units were granted to two officers in amounts equal
to 1% of our units outstanding at January 1, 2008 and the amount to be paid was
equal to the appreciation in value of the units, if any, from the date of the
grant until the determination date (December 31, 2008), plus cash distributions
paid on the units, less an 8% hurdle rate. These phantom units expired on
December 31, 2008 and no liability or expense was recognized as there was no
appreciation in the value of these units.





In
January 2009, new phantom units were granted to two officers equal to 1% of our
units outstanding at January 1, 2009, subject to the same terms as the 2008
phantom units. Additionally, in January 2009, four board members were each
granted 5,000 common units which will vest after one year.





These
common units, Class B units, options and phantom units were granted as partial
consideration for services to be performed under employment contracts and thus
are subject to accounting for these grants under SFAS 123(R),Share-Based Payment. With
respect to the 420,000 restricted Class B units granted, we expect to incur
$2.2 million and $0.1 million in non-cash compensation expense for the years
2009 and 2010, respectively. For the years ended December 31, 2008 and
2007, we recorded $3.6 million and $2.1 million of non-cash compensation
expense, respectively. Non-cash compensation expense to be incurred on the
40,000 Class B units to be issued in the future will be determined
based on the trading price of the units when they are granted.




Recently
      Adopted Accounting Pronouncements


In
September 2006, the Financial Accounting Standards Board (FASB) issued Statement
of Financial Accounting Standards No. 157 “FairValue Measurements” (“SFAS
157”). SFAS 157 introduces a framework for measuring fair value and expands
required disclosure about fair value measurements of assets and liabilities. On
February 6, 2008, the FASB issued a final FASB Staff Position (“FSP”) No. FAS
157-b, “Effective Date of FASB
Statement No. 157.” This FSP delays the effective date of SFAS 157 for
all non-financial assets and non-financial liabilities, except those that are
recognized or disclosed at fair value in the financial statements on a recurring
basis. In addition, the FSP removes certain leasing transactions from the scope
of SFAS 157. The effective date of SFAS 157 for non-financial assets and
non-financial liabilities has been delayed by one year to fiscal years beginning
after November 15, 2008 and interim periods within those fiscal years. SFAS 157
for financial assets and liabilities is effective for fiscal years beginning
after November 15, 2007, and the Company prospectively adopted the standard for
those assets and liabilities as of January 1, 2008. In adopting SFAS 157, the
Company determined that the impact of these additional assumptions on fair value
measurements did not have a material effect on financial position or results of
operations. The Company is still assessing the potential impact of
implementation in 2009 of those portions of the guidance for which the effective
date has been deferred by the FASB.





In
February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial
Assets and Financial Liabilities, including an amendment of FASB Statement No.
115”  (“SFAS 159”), which permits companies to choose, at
specified dates, to measure certain eligible financial instruments at fair
value. The objective of SFAS 159 is to reduce volatility in preparer reporting
that may be caused as a result of measuring related financial assets and
liabilities differently and to expand the use of fair value measurements. The
provisions of SFAS 159 apply only to entities that elect to use the fair value
option. Additional disclosures are also required 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 choose to adopt early. At the effective date, companies may elect
the fair value option for eligible items that exist at that date, and the effect
of the first remeasurement to fair value must be reported as a cumulative-effect
adjustment to the opening balance of retained earnings. Effective January 1,
2008, the Company adopted SFAS 159. Because the Company did not elect to apply
the provisions of SFAS 159 to any eligible financial instrument, the adoption
did not affect the consolidated financial statements.





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 Table of Contents







New
      Pronouncements Issued But Not Yet
Adopted







In
December 2007, the FASB issued SFAS No. 141 (revised 2007),“Business Combinations”
(“SFAS 141(R)”), which replaces FASB Statement No. 141. SFAS 141(R) establishes
principles and requirements for how an acquirer recognizes and measures in its
financial statements the identifiable assets acquired, the liabilities assumed,
any non-controlling interest in the acquiree and the goodwill acquired. The
Statement also establishes disclosure requirements that will enable users to
evaluate the nature and financial effects of the business combination. SFAS
141(R) is effective for acquisitions that occur in an entity’s fiscal year that
begins after December 15, 2008, which will be our fiscal year 2009. The impact,
if any, on the consolidated financial statements will depend on the nature and
size of business combinations that we consummate after the effective
date.





In
December 2007, the FASB issued SFAS No. 160,“Non-controlling Interests in
Consolidated Financial Statements—an amendment of ARB No. 51” (“SFAS
160”). SFAS 160 requires that accounting and reporting for minority interests
will be recharacterized as non-controlling interests and classified as a
component of equity. SFAS 160 also establishes reporting requirements that
provide sufficient disclosures that clearly identify and distinguish between the
interests of the parent and the interests of the non-controlling
owners. SFAS 160 applies to all entities that prepare consolidated
financial statements, except not-for-profit organizations, but will affect only
those entities that have an outstanding non-controlling interest in one or more
subsidiaries or that deconsolidate a subsidiary. This statement is effective as
of the beginning of an entity’s first fiscal year beginning after December 15,
2008, which will be our fiscal year 2009. Based upon the December 31, 2008
balance sheet, SFAS 160 would have no impact on the consolidated financial
statements.





In March
2008, the FASB issued SFAS No. 161, “Disclosures about Derivative
Instruments and Hedging Activities” (“SFAS 161”). SFAS 161 is intended to
improve financial reporting about derivative instruments and hedging activities
by requiring enhanced disclosures to enable investors to better understand their
effects on an entity’s financial position, financial performance, and cash
flows. SFAS 161 achieves these improvements by requiring disclosure of the fair
values of derivative instruments and their gains and losses in a tabular format.
It also provides more information about an entity’s liquidity by requiring
disclosure of derivative features that are credit risk-related. Finally, it
requires cross-referencing within footnotes to enable financial statement users
to locate important information about derivative instruments. SFAS 161 is
effective for financial statements issued for fiscal years and interim periods
beginning after November 15, 2008, with early application encouraged. We are
currently evaluating the impact of adopting SFAS 161 on our consolidated
financial statements.





In
December 2008, the SEC published a Final Rule, “Modernization of Oil and Gas
Reporting.”The new rule permits the use of new technologies to determine
proved reserves if those technologies have been demonstrated to lead to reliable
conclusions about reserves volumes. The new requirements also will allow
companies to disclose their probable and possible reserves to investors. In
addition, the new disclosure requirements require companies to: (a) report the independence
and qualifications of its reserves preparer or auditor; (b) file reports when a third
party is relied upon to prepare reserves estimates or conducts a reserves audit;
and (c) report oil and
gas reserves using an average price based upon the prior 12-month period rather
than year-end prices. The use of average prices will affect future impairment
and depletion calculations. The new disclosure requirements are effective for
annual reports on Forms 10-K for fiscal years ending on or after
December 31, 2009. A company may not apply the new rules to disclosures in
quarterly reports prior to the first annual report in which the revised
disclosures are required. The Company has not yet determined the impact of this
Final Rule, which will vary depending on changes in commodity prices, on its
disclosures, financial position or results of operations.





Capital
      Resources and Liquidity





Disruption
to Functioning of Capital Markets





Multiple
events during 2008 involving numerous financial institutions have effectively
restricted current liquidity within the capital markets throughout the United
States and around the world. Despite efforts by treasury and banking regulators
in the United States, Europe and other nations around the world to provide
liquidity to the financial sector, capital markets currently remain constrained.
We expect that our ability to issue debt and equity on favorable terms will be
limited as long as the capital markets remain constrained. We intend to move
forward with our development drilling program when market conditions allow for
an adequate return on a drilling investment and only when we have sufficient
liquidity to do so. The benefits expected to accrue to our unitholders from our
expansion activities may be muted by substantial cost of capital increases
during this period.





Natural
gas and oil prices historically have been volatile and are likely to continue to
be volatile in the future, especially given current geopolitical and economic
conditions. For example, the NYMEX crude oil spot price per barrel for the
period between January 1, 2008 and December 31, 2008 ranged from a high of
$145.29 to a low of $33.87 and the NYMEX natural gas spot price per MMBtu for
the period January 1, 2008 to December 31, 2008 ranged from a high of $13.58 to
a low of $5.29. As of March 5, 2009, the NYMEX crude oil spot price per barrel
was $43.61and the NYMEX natural gas spot price per MMBtu was $4.09.





Overview





48
 Table of Contents


We have
utilized private equity, proceeds from bank borrowings, cash flow from
operations, and the public equity markets for capital resources and
liquidity. To date, the primary use of capital has been for the acquisition
and development of natural gas and oil properties; however, as a result of our
IPO, we expect to distribute to unitholders a significant portion of our free
cash flow. As we execute our business strategy, we will continually monitor
the capital resources available to us to meet future financial obligations,
planned capital expenditures, acquisition capital and distributions to our
unitholders. Our future success in growing reserves, production and cash
flow will be highly dependent on the capital resources available to us and our
success in drilling for or acquiring additional reserves. We expect to fund
our capital expenditures and distributions to unitholders with cash flow from
operations, while funding any acquisition capital expenditures that we might
incur with borrowings under our reserve-based credit facility and publicly
offered equity, depending on market conditions. As of March 5, 2009, we
have $37.0 million available to be borrowed under our reserve-based credit
facility.





The
borrowing base is subject to adjustment from time to time but not less than on a
semi-annual basis based on the projected discounted present value (as determined
by independent petroleum engineers) of estimated future net cash flows
(utilizing the bank’s internal projection of future natural gas and oil prices)
from our proved natural gas and oil reserves. In October 2008, our borrowing
base was set at $175.0 million. Our next borrowing base redetermination is
scheduled for April 2009 utilizing our December 31, 2008 reserve
report.  Based on the current commodity price environment, banks have
lowered their internal projections of future natural gas and oil prices which
will decrease the borrowing base and thus decrease the amount available to be
borrowed under our reserve-based credit facility.  However, based on
preliminary discussions with our lead bank, due to our favorable hedging
contracts, we anticipate that the reduction would not be material to the
borrowing base as a whole and would not inhibit our ability to make
distributions to our unitholders.   If commodity prices continue
to decline and banks continue to lower their internal projections of natural gas
and oil prices, it is possible that we will be subject to decreases in our
borrowing base availability in the future.  As a result, to the extent
available after unitholder distributions, debt service, and capital
expenditures, it is our current intention to utilize our excess cash flow during
2009 to reduce our borrowings under our reserve-based credit facility. Based
upon current expectations, we believe existing liquidity and capital resources
will be sufficient for the conduct of our business and operations for the
foreseeable future.




Cash
      Flow from Operations





Net cash
provided by operating activities was $39.6 million during the year ended
December 31, 2008, compared to $1.4 million during the year ended
December 31, 2007 and $16.1 million during the year ended December 31,
2006. The increase in cash provided by operating activities during the year
ended December 31, 2008 was substantially due to increased income, after
adjusting for non-cash items, generated from increased production related to
acquisitions and higher average realized prices, a decrease in cash used in
price risk management activities and an increase in accounts payable accrued
expenses, offset by an increase in accounts receivable. The cash used in
operating activities during the year ended December 31, 2007 included the
termination of existing natural gas swaps at a cost of approximately $2.8
million, cash paid on early extinguishment of debt of approximately $2.5
million, the payment of $6.5 million for put option derivative contracts, and
the payment of $7.5 million of premiums to reset derivative strike prices at a
higher value.




Our cash
flow from operations is subject to many variables, the most significant of which
is the volatility of natural gas and oil prices. Natural gas and oil prices are
determined primarily by prevailing market conditions, which are dependent on
regional and worldwide economic and political activity, weather and other
factors beyond our control. Future cash flow from operations will depend on our
ability to maintain and increase production through our drilling program and
acquisitions, as well as the prices of natural gas and oil. We enter into
derivative contracts to reduce the impact of commodity price volatility on
operations. Currently, we use a combination of fixed-price swaps and NYMEX
collars and put options to reduce our exposure to the volatility in natural gas
and oil prices. Please read “Item 1—Operations—Price Risk Management
Activities” and “Item 7A—Quantitative and Qualitative Disclosures About Market
Risk” for details about derivatives in place through 2012.




Investing
      Activities—Acquisitions and Capital
Expenditures


Our
capital expenditures were $119.5 million in the year ended December 31,
2008, and $26.4 million and $37.4 million for the years ended December 31,
2007 and 2006, respectively. The increase in cash used in investing activities
was primarily attributable to $100.7 million used for the acquisition of natural
gas and oil properties in the Permian Basin and south Texas. In addition, the
total for the year ended December 31, 2008 includes $18.2 million for the
drilling and development of natural gas and oil properties as compared to $12.8
million for the year ended December 31, 2007. The total for 2007 includes $3.6
million for acquisitions of natural gas and oil properties and $9.8 million for
deposits on acquisition of and prepayments of natural gas and oil properties.
There were no acquisitions during 2006. The totals for 2006 include $28.9
million for drilling and development of natural gas properties, and $8.5 million
for furniture, fixtures and equipment, respectively, which includes expenditures
for extensions of the gathering system and related midstream activities. The
furniture, fixtures and equipment were retained by our Predecessor in the
Restructuring.




Excluding
any potential acquisitions, we currently anticipate a capital budget for 2009 of
between $6.0 million and $6.5 million, which predominantly consists of
recompletions and workovers of existing wells and a limited amount of new
drilling in south Texas in the second half of 2009. This capital budget is
expected to be funded through cash from operations. As of March 5, 2009, we
had




49
 Table of Contents


$37.0
million available for borrowing under our reserve-based credit facility. Our
current borrowing base is $175.0 million. Our next borrowing base
redetermination is scheduled for April 2009 utilizing our December 31, 2008
reserve report.  Based on the current commodity price environment,
banks have lowered their internal projections of future natural gas and oil
prices which will decrease the borrowing base and thus decrease the amount
available to be borrowed under our reserve-based credit
facility.  However, based on preliminary discussions with our lead
bank, due to our favorable hedging contracts, we anticipate that the reduction
would not be material to the borrowing base as a whole. If commodity prices
continue to decline and banks continue to lower their internal projections of
natural gas and oil prices, it is possible that we will be subject to decreases
in our borrowing base availability in the future. We anticipate that our cash
flow from operations and available borrowing capacity under our reserve-based
credit facility will exceed our planned capital expenditures and other cash
requirements for the year ended December 31, 2009. However, future cash
flows are subject to a number of variables, including the level of natural gas
production and prices. There can be no assurance that operations and other
capital resources will provide cash in sufficient amounts to maintain planned
levels of capital expenditures.




Financing
      Activities





Cash
provided by financing activities was approximately $76.9 million for the year
ended December 31, 2008, compared to $26.4 million for the year ended December
31, 2007. During the year ended December 31, 2008, total proceeds from
borrowings under our reserve-based credit facility, net of repayments were $97.6
million which were used to fund the Permian Basin and south Texas acquisitions.
During the year ended December 31, 2007, total proceeds from borrowings under
our reserve-based credit facility were $126.2 million, which were principally
used to pay off our Predecessor’s outstanding borrowings. Additionally, during
the year ended December 31, 2007, we completed a private equity offering for
$41.2 million and used the net proceeds of this private equity offering to make
a distribution to Majeed S. Nami, VNR’s sole member at that time.




Available
Credit





Credit
markets in the United States and around the world remain constrained due to a
lack of liquidity and confidence in a number of financial institutions.
Investors continue to seek perceived safe investments in securities of the
United States government rather than individual entities. We may experience
difficulty accessing the long-term credit markets due to prevailing market
conditions. Additionally, existing constraints in the credit markets may
increase the rates we are charged for utilizing these markets. Notwithstanding
the continuing weakness in the United States credit markets, we expect that our
available liquidity is sufficient to meet our operating and capital requirements
into 2009.





Reserve-Based
Credit Facility





On
January 3, 2007, we entered into a reserve-based credit facility under which our
initial borrowing base was set at $115.5 million. Our reserve-based credit
facility was amended and restated in February 2008 to extend the maturity date
from January 2011 to March 2011, increase the maximum facility amount from
$200.0 million to $400.0 million, increase our borrowing base from $110.5
million to $150.0 million and add two additional financial institutions as
lenders, Wachovia Bank, N.A. and the Bank of Nova Scotia. The increase in the
borrowing base was principally the result of inclusion of the reserves related
to the Permian Basin acquisition in January 2008. In May 2008, our reserve-based
credit facility was amended in response to a potential acquisition that
ultimately did not occur. As a result, none of the provisions included in this
amendment went into effect. As of October 22, 2008, our reserve-based credit
facility was amended and restated to increase the borrowing base to $175.0
million and add one lender, Compass Bank. The increase in the borrowing base was
principally the result of inclusion of the reserves related to the south Texas
acquisition in July 2008. At December 31, 2008, we had $135.0 million
outstanding under our reserve-based credit facility and as of March 5,
2009, we have $37.0 million available to be borrowed under our reserve-based
credit facility.


The
borrowing base is subject to adjustment from time to time but not less than on a
semi-annual basis based on the projected discounted present value (as determined
by independent petroleum engineers) of estimated future net cash flows
(utilizing the bank’s internal projection of future natural gas and oil prices)
from our proved natural gas and oil reserves. In October 2008, our borrowing
base was set at $175.0 million. Our next borrowing base redetermination is
scheduled for April 2009 utilizing our December 31, 2008 reserve
report.  Based on the current commodity price environment, banks have
lowered their internal projections of future natural gas and oil prices which
will decrease the borrowing base and thus decrease the amount available to be
borrowed under our reserve-based credit facility.  However, based on
preliminary discussions with our lead bank, due to our favorable hedging
contracts, we anticipate that the reduction would not be material to the
borrowing base as a whole. If commodity prices continue to decline and banks
continue to lower their internal projections of natural gas and oil prices, it
is possible that we will be subject to decreases in our borrowing base
availability in the future. As a result, absent accretive acquisitions, it is
our current intention to utilize our excess cash flow during 2009 to reduce our
borrowings under our reserve-based credit facility.





Borrowings
under the reserve-based credit facility are available for development and
acquisition of natural gas and oil properties, working capital and general
limited liability company purposes. Our obligations under the reserve-based
credit facility are secured by substantially all of our assets.




At our
election, interest is determined by reference to:




50
 Table of Contents




·
            the
      London interbank offered rate, or LIBOR, plus an applicable margin between
      1.50% and 2.125% per annum; or





·
            a
      domestic bank rate plus an applicable margin between 0.00% and 0.75% per
      annum.





As of
December 31, 2008, we have elected for interest to be determined by reference to
the LIBOR method described above.





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




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




·
            incur
      indebtedness;




·
            grant
      certain liens;





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





·
            make
      distributions;





·
            merge
      or consolidate; or





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





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





·
            consolidated
      net income plus interest expense, income taxes, depreciation, depletion,
      amortization, accretion, impairment, changes in fair value of derivative
      instruments and other similar charges, minus all non-cash income added to
      consolidated net income, the aggregate amount of cash used to purchase our
      own units during the preceding twelve months and giving pro forma effect
      to any acquisitions or capital expenditures, to interest expense of not
      less than 2.5 to 1.0;





·
            consolidated
      current assets, including the unused amount of the total commitments, to
      consolidated current liabilities of not less than 1.0 to 1.0, excluding
      non-cash assets and liabilities under SFAS 133, which includes the current
      portion of derivative contracts;




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




We have
the ability to borrow under the reserve-based credit facility to pay
distributions to unitholders as long as there has not been a default or event of
default and if the amount of borrowings outstanding under our reserve-based
credit facility is less than 90% of the borrowing base.




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




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





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





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





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




51
 Table of Contents




·
            bankruptcy
      or insolvency events involving us or our
  subsidiaries;





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





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




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





Off-Balance
Sheet Arrangements





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




Contingencies




The
Company regularly analyzes current information and accrues for probable
liabilities on the disposition of certain matters, as necessary. Liabilities for
loss contingencies arising from claims, assessments, litigation and other
sources are recorded when it is probable that a liability has been incurred and
the amount can be reasonably estimated. As of December 31, 2008, there were
no material loss contingencies.




Commitments
and Contractual Obligations





A summary
of our contractual obligations as of December 31, 2008 is provided in the
following table.




Payments Due by Year (in thousands)2009
                                                                                                                                                
                                                                                                                                                
                                                                                                                                                2010
                                                                                                                                                
                                                                                                                                                
                                                                                                                                                2011
                                                                                                                                                
                                                                                                                                                
                                                                                                                                                2012
                                                                                                                                                
                                                                                                                                                
                                                                                                                                                2013
                                                                                                                                                
                                                                                                                                                
                                                                                                                                                After 2013
                                                                                                                                                
                                                                                                                                                
                                                                                                                                                TotalManagement
      compensation
                                                                                                                                                
                                                                                                                                                $
                                                                                                                                                600
                                                                                                                                                
                                                                                                                                                
                                                                                                                                                $
                                                                                                                                                100
                                                                                                                                                
                                                                                                                                                
                                                                                                                                                $
                                                                                                                                                —
                                                                                                                                                
                                                                                                                                                
                                                                                                                                                $
                                                                                                                                                —
                                                                                                                                                
                                                                                                                                                
                                                                                                                                                $
                                                                                                                                                —
                                                                                                                                                
                                                                                                                                                
                                                                                                                                                $
                                                                                                                                                —
                                                                                                                                                
                                                                                                                                                
                                                                                                                                                $
                                                                                                                                                700Asset
      retirement obligations
                                                                                                                                                
                                                                                                                                                
                                                                                                                                                —
                                                                                                                                                
                                                                                                                                                
                                                                                                                                                
                                                                                                                                                37
                                                                                                                                                
                                                                                                                                                
                                                                                                                                                
                                                                                                                                                183
                                                                                                                                                
                                                                                                                                                
                                                                                                                                                
                                                                                                                                                32
                                                                                                                                                
                                                                                                                                                
                                                                                                                                                
                                                                                                                                                14
                                                                                                                                                
                                                                                                                                                
                                                                                                                                                
                                                                                                                                                1,868
                                                                                                                                                
                                                                                                                                                
                                                                                                                                                
                                                                                                                                                2,134Derivative
      liabilities
                                                                                                                                                
                                                                                                                                                
                                                                                                                                                677
                                                                                                                                                
                                                                                                                                                
                                                                                                                                                
                                                                                                                                                1,225
                                                                                                                                                
                                                                                                                                                
                                                                                                                                                
                                                                                                                                                1,445
                                                                                                                                                
                                                                                                                                                
                                                                                                                                                
                                                                                                                                                1,102
                                                                                                                                                
                                                                                                                                                
                                                                                                                                                
                                                                                                                                                292
                                                                                                                                                
                                                                                                                                                
                                                                                                                                                
                                                                                                                                                —
                                                                                                                                                
                                                                                                                                                
                                                                                                                                                
                                                                                                                                                4,741Long-term
      debt (1)
                                                                                                                                                
                                                                                                                                                
                                                                                                                                                —
                                                                                                                                                
                                                                                                                                                
                                                                                                                                                
                                                                                                                                                —
                                                                                                                                                
                                                                                                                                                
                                                                                                                                                
                                                                                                                                                135,000
                                                                                                                                                
                                                                                                                                                
                                                                                                                                                
                                                                                                                                                —
                                                                                                                                                
                                                                                                                                                
                                                                                                                                                
                                                                                                                                                —
                                                                                                                                                
                                                                                                                                                
                                                                                                                                                
                                                                                                                                                —
                                                                                                                                                
                                                                                                                                                
                                                                                                                                                
                                                                                                                                                135,000Operating
      leases (2)
                                                                                                                                                
                                                                                                                                                
                                                                                                                                                154
                                                                                                                                                
                                                                                                                                                
                                                                                                                                                
                                                                                                                                                41
                                                                                                                                                
                                                                                                                                                
                                                                                                                                                
                                                                                                                                                —
                                                                                                                                                
                                                                                                                                                
                                                                                                                                                
                                                                                                                                                —
                                                                                                                                                
                                                                                                                                                
                                                                                                                                                
                                                                                                                                                —
                                                                                                                                                
                                                                                                                                                
                                                                                                                                                
                                                                                                                                                —
                                                                                                                                                
                                                                                                                                                
                                                                                                                                                
                                                                                                                                                195Total
                                                                                                                                                
                                                                                                                                                $
                                                                                                                                                1,431
                                                                                                                                                
                                                                                                                                                
                                                                                                                                                $
                                                                                                                                                1,403
                                                                                                                                                
                                                                                                                                                
                                                                                                                                                $
                                                                                                                                                136,628
                                                                                                                                                
                                                                                                                                                
                                                                                                                                                $
                                                                                                                                                1,134
                                                                                                                                                
                                                                                                                                                
                                                                                                                                                $
                                                                                                                                                306
                                                                                                                                                
                                                                                                                                                
                                                                                                                                                $
                                                                                                                                                1,868
                                                                                                                                                
                                                                                                                                                
                                                                                                                                                $
                                                                                                                                                142,770





(1)
            This
      table does not include interest to be paid on the principal balances shown
      as the interest rates on the reserve-based credit facility are
      variable.(2)
            Includes
      lease agreement entered into in February 2009 which expires in
      April 2010.




ITEM 7A.
            QUANTITATIVE
      AND QUALITATIVE DISCLOSURES ABOUT MARKET
RISK




The
primary objective of the following information is to provide forward-looking
quantitative and qualitative information about our potential exposure to market
risks. The term “market risk” refers to the risk of loss arising from adverse
changes in natural gas and oil prices and interest rates. The disclosures are
not meant to be precise indicators of expected future losses, but rather
indicators of




52
 Table of Contents




reasonably
possible losses. This forward-looking information provides indicators of how we
view and manage our ongoing market risk exposures. All of our market risk
sensitive instruments were entered into for purposes other than speculative
trading. Conditions sometimes arise where actual production is less than
estimated, which has, and could result in overhedged volumes.




Commodity
Price Risk





Our major
market risk exposure is in the pricing applicable to our natural gas and oil
production. Realized pricing is primarily driven by the Columbia Gas Appalachian
Index (“TECO Index”), Henry Hub and Houston Ship Channel prices for natural gas
production and the West Texas Intermediate Light Sweet price for oil production.
Pricing for natural gas and oil production has been volatile and unpredictable
for several years, and we expect this volatility to continue in the future. The
prices we receive for production depend on many factors outside our control. In
addition, the potential exists that if commodity prices decline to a certain
level, the borrowing base can be decreased at the borrowing base redetermination
date to an amount lower than the amount of debt currently outstanding and,
because it would be uneconomical, production could decline to levels below our
hedged volumes.





Furthermore, the
risk that we will be required to write down the carrying value of our natural
gas and oil properties increases when oil and gas prices are low or volatile. In
addition, write downs may occur if we experience substantial downward
adjustments to our estimated proved reserves, or if estimated future development
costs increase. For example, natural gas and oil prices declined significantly
throughout the second half of 2008. We recorded a non-cash ceiling test
impairment of natural gas and oil properties for the year ended December 31,
2008 of $58.9 million as a result of a decline in natural gas and oil prices at
the measurement date.  This impairment was calculated based on prices
of $5.71 per MMBtu for natural gas and $41.00 per barrel of crude oil. Additionally, if natural
gas prices decline by $1.00 per MMBtu or 18% and oil prices declined by $6.00
per barrel or 15%, the standardized measure of our proved reserves as of
December 31, 2008 would decrease from $190.1 million to $138.1 million,
based on price sensitivity generated from an internal
evaluation.




We enter
into derivative contracts with respect to a portion of our projected natural gas
and oil production through various transactions that mitigate the volatility of
future prices received. These transactions may include price swaps whereby we
will receive a fixed-price for our production and pay a variable market price to
the contract counterparty. Additionally, we have put options for which we pay
the counterparty and option premium, equal to the fair value of the option at
the purchase date. At the settlement date we receive the excess, if any, of the
fixed floor over the floating rate. Furthermore, we may enter into collars where
we pay the counterparty if the market price is above the ceiling price and the
counterparty pays us if the market price is below the floor on a notional
quantity. These activities are intended to support our realized commodity prices
at targeted levels and to manage our exposure to natural gas and oil price
fluctuations. It is never management’s intention to hold or issue derivative
instruments for speculative trading purposes.




At
December 31, 2008, the fair value of commodity derivative contracts was an
asset of approximately $37.9 million, of which $22.2 million settle during
the next twelve months. A 10% increase in the gas and oil index price above the
December 31, 2008 price would result in a decrease in the fair value of all
of our commodity derivative contracts of approximately $5.3 million; conversely,
a 10% decrease in the gas and oil index price would result in an increase
of approximately $5.4 million.




The
following table summarizes commodity derivative contracts in place at
December 31, 2008:





2009
                
                
                2010
                
                
                2011
                
                
                2012Gas
      Positions:Fixed
      Price Swaps:Notional
      Volume (MMBtu)
                
                
                3,629,946
                
                
                
                3,236,040
                
                
                
                2,962,312
                
                
                
                —Fixed
      Price ($/MMBtu)
                
                $
                9.42
                
                
                $
                9.10
                
                
                $
                7.82
                
                
                $
                —Puts:Notional
      Volume (MMBtu)
                
                
                840,143
                
                
                
                —
                
                
                
                —
                
                
                
                —Floor
      Price ($/MMBtu)
                
                $
                7.50
                
                
                $
                —
                
                
                $
                —
                
                
                $
                —Collars:Notional
      Volume (MMBtu)
                
                
                1,000,000
                
                
                
                730,000
                
                
                
                —
                
                
                
                —Floor
      Price ($/MMBtu)
                
                $
                7.50
                
                
                $
                8.00
                
                
                $
                —
                
                
                $
                —Ceiling
      Price ($/MMBtu)
                
                $
                9.00
                
                
                $
                9.30
                
                
                $
                —
                
                
                $
                —Total:Notional
      Volume (MMBtu)
                
                
                5,470,089
                
                
                
                3,966,040
                
                
                
                2,962,312
                
                
                
                —  53
 Table of Contents
  Oil
      Positions:Fixed
      Price Swaps:Notional
      Volume (Bbls)
                
                
                181,500
                
                
                
                164,250
                
                
                
                151,250
                
                
                
                144,000Fixed
      Price ($/Bbl)
                
                $
                87.23
                
                
                $
                85.65
                
                
                $
                85.50
                
                
                $
                80.00Collars:Notional
      Volume (Bbls)
                
                
                36,500
                
                
                
                —
                
                
                
                —
                
                
                
                —Floor
      Price ($/Bbl)
                
                $
                100.00
                
                
                $
                —
                
                
                $
                —
                
                
                $
                —Ceiling
      Price ($/Bbl)
                
                $
                127.00
                
                
                $
                —
                
                
                $
                —
                
                
                $
                —Total:Notional
      Volume (Bbls)
                
                
                218,000
                
                
                
                164,250
                
                
                
                151,250
                
                
                
                144,000





In
February 2009, we liquidated our 2012 oil swap and entered into new 2010 and
2011 natural gas swap and collar transactions. Specifically, an $8.04 and $7.85
fixed price NYMEX natural gas swap for January through September 2010 and April
through September 2011, respectively, was executed for 2,000 MMBtu/day. In
addition, a 2,000 MMBtu/day NYMEX natural gas collar with a floor price of $7.50
and a ceiling price of $9.00 for October 2010 through March 2011 and October
2011 through December 2011 was executed. These natural gas derivatives were set
at prices above the current market by using the proceeds of the liquidation of
the 2012 oil swap.





Interest
      Rate Risks





At
December 31, 2008, we had debt outstanding of $135.0 million, which
incurred interest at floating rates based on LIBOR in accordance with our
reserve-based credit facility and if the debt remains the same, a 1% increase in
LIBOR would result in an estimated $0.4 million increase in annual interest
expense after consideration of the interest rate swaps discussed below. In
December 2007 and during 2008, we entered into interest rate swaps,
which require exchanges of cash flows that serve to synthetically convert a
portion of our variable interest rate exposures to fixed interest
rates.




In August
2008, we entered into two interest rate basis swaps which changed the reset
option from three month LIBOR to one month LIBOR on the total $60.0 million of
outstanding interest rate swaps. By doing so, the company reduced its borrowing
cost by 14 basis points on $20.0 million of borrowings for a one year period
starting September 10, 2008 and 12 basis points on $40.0 million of borrowings
for a one year period starting October 31, 2008. As a result of these two basis
swaps, the company chose to de-designate the interest rate swaps as cash flow
hedges as the terms of the new contracts no longer matched the terms of the
original contracts, thus causing the interest rate hedges to be ineffective.
Beginning in the third quarter of 2008, the Company recorded changes in the fair
value of its interest rate derivatives in current earnings under gains (losses)
on interest rate derivative contracts. The net unrealized gain related to the
de-designated cash flow hedges is reported in accumulated other comprehensive
income and later reclassified to earnings in the month in which the transactions
settle.





The
following summarizes information concerning our positions in open interest rate
swaps at December 31, 2008.




Notional
                    Amount
                  
                  Fixed
                    Libor
                    RatesPeriod:January
      1, 2009 to December 10, 2010
                  
                  $
                  10,000,000
                  
                  1.50
                  %January
      1, 2009 to December 20, 2010
                  
                  $
                  10,000,000
                  
                  1.85
                  %January
      1, 2009 to January 31, 2011
                  
                  $
                  20,000,000
                  
                  3.00
                  %January
      1, 2009 to March 31, 2011
                  
                  $
                  20,000,000
                  
                  2.08
                  %January
      1, 2009 to December 10, 2012
                  
                  $
                  20,000,000
                  
                  3.35
                  %January
      1, 2009 to January 31, 2013
                  
                  $
                  20,000,000
                  
                  2.38
                  %January
      1, 2009 to September 10, 2009 (Basis Swap)
                  
                  $
                  20,000,000
                  
                  LIBOR
      1M vs. LIBOR 3MJanuary
      1, 2009 to October 31, 2009 (Basis Swap)
                  
                  $
                  40,000,000
                  
                  LIBOR
      1M vs. LIBOR 3M





54
 Table of Contents










ITEM 8.
            FINANCIAL
      STATEMENTS AND SUPPLEMENTARY DATA




Index




Below is
an index to the items contained in Part II, Item 8, Financial
Statements and Supplementary Data.




PageReports of Independent Registered Public Accounting
      Firms
              56Consolidated Statements of
    Operations
              59Consolidated Balance Sheets
              60Consolidated Statements of Members’
      Equity
              61Consolidated Statements of Cash Flows
              62Consolidated Statements of Other Comprehensive Income
      (Loss)
              63Notes to Consolidated Financial
    Statements
              64Supplemental Financial
    InformationSupplemental Selected Quarterly Financial
      Information (Unaudited)
              78Supplemental Natural Gas and Oil Operations
      (Unaudited)
              79








All schedules are omitted as the
required information is not applicable or the information is presented in the
Consolidated Financial Statements and related notes.







55
 Table of Contents





REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM




Board of
Directors and Members


Vanguard
Natural Resources, LLC


Houston,
Texas




We have
audited the accompanying consolidated balance sheet of Vanguard Natural
Resources, LLC as of December 31, 2008 and the related consolidated statements
of operations, comprehensive income (loss), members’ equity and cash flows for
the year then ended. These financial statements are the responsibility of the
Company’s management.  Our responsibility is to express an opinion on
these financial statements based on our audit.




We
conducted our audit in accordance with the standards of the Public Company
Accounting Oversight Board (United States).  Those standards require
that we plan and perform the audit to obtain reasonable assurance about whether
the financial statements are free of material misstatement.  An audit
includes examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements, assessing the accounting principles
used and significant estimates made by management, as well as evaluating the
overall financial statement presentation.  We believe that our audit
provides a reasonable basis for our opinion.




In our
opinion, the consolidated financial statements referred to above present fairly,
in all material respects, the financial position of Vanguard Natural Resources,
LLC at December 31, 2008, and the results of its operations and its cash flows
for the year then ended,
in conformity with accounting principles generally accepted in the United States
of America.




We also
have audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), Vanguard Natural Resources, LLC's internal
control over financial reporting as of December 31, 2008, based on criteria
established in Internal
Control – Integrated Frameworkissued by the Committee of Sponsoring
Organizations of the Treadway Commission (COSO) and our report dated March 10,
2009 expressed an unqualified opinion thereon.









/s/ BDO
Seidman, LLP






Houston,
Texas


March 10,
2009










56
 Table of Contents














REPORT
OF 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 of Vanguard Natural
Resources, LLC (a Delaware limited liability company) and subsidiaries (the
“Company”) as of December 31, 2007, and the related consolidated statements
of operations, members’ equity, comprehensive income and cash flows for the year
then ended. These consolidated financial statements are the responsibility of
the Company’s management. Our responsibility is to express an opinion on these
consolidated financial statements based on our audit.




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




In our
opinion, the consolidated financial statements referred to above present fairly,
in all material respects, the consolidated financial position of Vanguard
Natural Resources, LLC and subsidiaries as of December 31, 2007, and the
consolidated results of their operations and their cash flows for the year then
ended, in conformity with accounting principles generally accepted in the United
States of America.










/s/ UHY
LLP




Houston,
Texas


March 31,
2008










57
 Table of Contents







REPORT
OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM




To the
Members of


Vanguard
Natural Gas, LLC


and
Subsidiaries




We have
audited the accompanying consolidated statements of operations and cash flows of
Vanguard Natural Gas, LLC (formerly Nami Holding Company, LLC), and subsidiaries
(the “Company”) for the year ended December 31, 2006. These consolidated
financial statements are the responsibility of the Company’s management. Our
responsibility is to express an opinion on these consolidated financial
statements based on our audit.





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





In our
opinion, the consolidated financial statements referred to above present fairly,
in all material respects, the consolidated results of operations and cash flows
of Vanguard Natural Gas, LLC and subsidiaries for the year ended
December 31, 2006, in conformity with accounting principles generally
accepted in the United States of America.




/s/ UHY
LLP




Houston,
Texas


April 20,
2007





58
 Table of Contents










Vanguard Natural Resources, LLC and
Subsidiaries


Consolidated
Statements of Operations


For
the Years Ended December 31,





Vanguard
                
                
                Vanguard
      Predecessor2008
                
                
                2007
                
                
                2006RevenuesNatural gas and oil
      sales
                
                $
                68,850,004
                
                
                $
                34,540,500
                
                
                $
                38,849,142Gain (loss) on commodity cash
      flow hedges
                
                
                269,260
                
                
                
                (701,675
                )
                
                
                —Gain on other commodity
      derivative contracts
                
                
                32,476,472
                
                
                
                —
                
                
                
                15,539,915Total
    revenues
                
                
                101,595,736
                
                
                
                33,838,825
                
                
                
                54,389,057Costs
      and expensesLease operating
      expenses
                
                
                11,111,849
                
                
                
                5,066,230
                
                
                
                4,896,327Depreciation, depletion,
      amortization and accretion
                
                
                14,910,454
                
                
                
                8,981,179
                
                
                
                8,633,235Impairment of natural gas and oil
      properties
                
                
                58,886,660
                
                
                
                —
                
                
                
                —Selling, general and
      administrative expenses
                
                
                6,715,036
                
                
                
                3,506,539
                
                
                
                5,198,760Bad debt
      expense
                
                
                —
                
                
                
                1,007,458
                
                
                
                —Production and other
      taxes
                
                
                4,964,987
                
                
                
                2,053,604
                
                
                
                1,774,215Total costs and
      expenses
                
                
                96,588,986
                
                
                
                20,615,010
                
                
                
                20,502,537Income
      from operations
                
                
                5,006,750
                
                
                
                13,223,815
                
                
                
                33,886,520Other
      income (expense)Interest
    income
                
                
                17,232
                
                
                
                61,621
                
                
                
                40,256Interest
      expense
                
                
                (5,490,816
                )
                
                
                (8,134,600
                )
                
                
                (7,371,930
                )Loss on interest rate derivative
      contracts
                
                
                (3,284,514
                )
                
                
                —
                
                
                
                —Loss on extinguishment of debt
      expense
                
                
                —
                
                
                
                (2,501,528
                )
                
                
                —Total other
      expense
                
                
                (8,758,098
                )
                
                
                (10,574,507
                )
                
                
                (7,331,674
                )Net
      income (loss)
                
                $
                (3,751,348
                )
                
                $
                2,649,308
                
                
                $
                26,554,846Net
      income (loss) per unit:Common and Class B
      units - basic
                
                $
                (0.32
                )
                
                $
                0.39Common and Class B
      units - diluted
                
                $
                (0.32
                )
                
                $
                0.39Weighted
      average units outstanding:Common units – basic &
      diluted
                
                
                11,374,473
                
                
                
                6,533,411Class B units –
      basic & diluted
                
                
                420,000
                
                
                
                278,945











See
accompanying notes to consolidated financial statements.







59
 Table of Contents





Vanguard Natural Resources, LLC and Subsidiaries


Consolidated
Balance Sheets


As
of December 31,




2008
                        
                        
                        2007AssetsCurrent
      assetsCash
      and cash equivalents
                        
                        $
                        2,616
                        
                        
                        $
                        3,109,563Trade
      accounts receivable, net
                        
                        
                        6,083,479
                        
                        
                        
                        3,875,078Derivative
      assets
                        
                        
                        22,183,648
                        
                        
                        
                        4,017,085Other
      receivables
                        
                        
                        2,762,730
                        
                        
                        
                        497,653Other
      currents assets
                        
                        
                        845,404
                        
                        
                        
                        453,198Total
      current assets
                        
                        
                        31,877,877
                        
                        
                        
                        11,952,577Property
      and equipment, net of accumulated depreciation
                        
                        
                        184,224
                        
                        
                        
                        166,455Natural
      gas and oil properties, at cost
                        
                        
                        284,446,984
                        
                        
                        
                        135,435,240Accumulated
      depletion, amortization and accretion
                        
                        
                        (102,178,304
                        )
                        
                        
                        (28,451,891
                        )Natural
      gas and oil properties evaluated, net – full cost method
                        
                        
                        182,268,680
                        
                        
                        
                        106,983,349Other
      assetsDerivative
      assets
                        
                        
                        15,748,721
                        
                        
                        
                        1,329,511Deferred
      financing costs
                        
                        
                        881,996
                        
                        
                        
                        941,833Non-current
      deposits
                        
                        
                        45,963
                        
                        
                        
                        8,285,883Other
      assets
                        
                        
                        1,554,416
                        
                        
                        
                        1,519,577Total
      assets
                        
                        $
                        232,561,877
                        
                        
                        $
                        131,179,185Liabilities
      and members’ equityCurrent
      liabilitiesAccounts
      payable –
      trade
                        
                        $
                        2,147,664
                        
                        
                        $
                        1,056,627Accounts
      payable – natural
      gas and oil
                        
                        
                        1,327,361
                        
                        
                        
                        257,073Payables
      to affiliates
                        
                        
                        2,554,624
                        
                        
                        
                        3,838,328Derivative
      liabilities
                        
                        
                        486,576
                        
                        
                        
                        —Accrued
      expenses
                        
                        
                        1,247,606
                        
                        
                        
                        203,159Total
      current liabilities
                        
                        
                        7,763,831
                        
                        
                        
                        5,355,187Long-term
      debt
                        
                        
                        135,000,000
                        
                        
                        
                        37,400,000Derivative
      liabilities
                        
                        
                        2,313,335
                        
                        
                        
                        5,903,384Asset
      retirement obligations
                        
                        
                        2,133,791
                        
                        
                        
                        189,711Total
      liabilities
                        
                        
                        147,210,957
                        
                        
                        
                        48,848,282Commitments
      and contingencies (Note 9)Members’
      equityMembers’
      capital, 12,145,873 and 10,795,000 common units issued and outstanding at
      December 31, 2008 and 2007, respectively
                        
                        
                        88,550,178
                        
                        
                        
                        90,257,856Class B
      units, 420,000 issued and outstanding at December 31, 2008 and
      2007
                        
                        
                        4,605,463
                        
                        
                        
                        2,131,995Accumulated
      other comprehensive loss
                        
                        
                        (7,804,721
                        )
                        
                        
                        (10,058,948
                        )Total
      members’ equity
                        
                        
                        85,350,920
                        
                        
                        
                        82,330,903Total
      liabilities and members’ equity
                        
                        $
                        232,561,877
                        
                        
                        $
                        131,179,185




See
accompanying notes to consolidated financial statements.





60
 Table of Contents













Vanguard Natural Resources, LLC and
Subsidiaries


Consolidated
Statements of Members’ Equity


For
the Years Ended December 31, 2008 and 2007




Common
                              Units
                            
                            Class B
                              Units
                            
                            Total
      Members’
                              EquityBalance,January 1,
      2007
                            —
                            
                            —
                            
                            $
                            —Initial
      contribution
                            5,540,000
                            
                            —
                            
                            3,289,055Sale
      of private placement units
                            —
                            
                            —
                            
                            41,220,000Distribution
      to member
                            —
                            
                            —
                            
                            (41,220,000
                            )Issuance
      of common units, net of offering costs of $9,804,085
                            5,250,000
                            
                            —
                            
                            89,945,916Distribution
      to members
                            —
                            
                            —
                            
                            (5,626,423
                            )Unit-based
      compensation
                            5,000
                            
                            420,000
                            
                            2,131,995Net
      income
                            —
                            
                            —
                            
                            2,649,308Changes
      in fair value of cash flow hedges
                            —
                            
                            —
                            
                            (10,058,948
                            )Balance,December 31,
      2007
                            10,795,000
                            
                            420,000
                            
                            $
                            82,330,903Distribution
      to members ($0.291, $0.445, $0.445 and $0.50 per unit to unit holders of
      record on February 7, 2008, April 30, 2008, July 31, 2008 and October 31,
      2008, respectively)
                            —
                            
                            —
                            
                            
                            (20,128,990
                            )Issuance
      of common units for acquisition of natural gas and oil properties, net of
      offering costs of $54,191
                            1,350,873
                            
                            —
                            
                            
                            21,305,809Unit-based
      compensation
                            —
                            
                            —
                            
                            
                            3,340,319Settlement
      of cash flow hedges in other comprehensive income
                            —
                            
                            —
                            
                            
                            2,254,227Net
      loss
                            —
                            
                            —
                            
                            
                            (3,751,348
                            )Balance,December 31,
      2008
                            12,145,873
                            
                            420,000
                            
                            $
                            85,350,920




See
accompanying notes to consolidated financial statements.







61
 Table of Contents








Vanguard Natural Resources, LLC and Subsidiaries


Consolidated
Statements of Cash Flows


For
the Years Ended December 31,


Vanguard
                                
                                
                                Vanguard
      Predecessor2008
                                
                                
                                2007
                                
                                
                                2006Operating
      activitiesNet
      income (loss)
                                
                                $
                                (3,751,348
                                )
                                
                                $
                                2,649,308
                                
                                
                                $
                                26,554,846Adjustments
      to reconcile net income (loss) to net cash provided by operating
      activities:Depreciation,
      depletion, amortization and accretion
                                
                                
                                14,910,454
                                
                                
                                
                                8,981,179
                                
                                
                                
                                8,633,235Impairment
      of natural gas and oil properties
                                
                                
                                58,886,660
                                
                                
                                
                                —
                                
                                
                                
                                —Amortization
      of deferred financing costs
                                
                                
                                362,400
                                
                                
                                
                                296,115
                                
                                
                                
                                —Bad
      debt expense
                                
                                
                                —
                                
                                
                                
                                1,007,458
                                
                                
                                
                                —Unit-based
      compensation
                                
                                
                                3,576,558
                                
                                
                                
                                2,131,995
                                
                                
                                
                                —Amortization
      of premiums paid and non-cash settlements on derivative
      contracts
                                
                                
                                5,226,465
                                
                                
                                
                                4,274,120
                                
                                
                                
                                —Unrealized
      gains on other commodity and interest rate derivative
      contracts
                                
                                
                                (35,851,133
                                )
                                
                                
                                —
                                
                                
                                
                                (17,747,817
                                )Changes
      in operating assets and liabilities:Trade
      accounts receivable
                                
                                
                                (2,208,401
                                )
                                
                                
                                (504,683
                                )
                                
                                
                                1,634,402Payables
      to affiliates
                                
                                
                                (1,850,094
                                )
                                
                                
                                (530,809
                                )
                                
                                
                                (3,448,823
                                )Price
      risk management activities, net
                                
                                
                                (342,778
                                )
                                
                                
                                (15,798,359
                                )
                                
                                
                                —Other
      receivables
                                
                                
                                (2,265,077
                                )
                                
                                
                                —
                                
                                
                                
                                1,004,464Inventory
                                
                                
                                —
                                
                                
                                
                                —
                                
                                
                                
                                (54,988
                                )Other
      current assets
                                
                                
                                (344,940
                                )
                                
                                
                                (340,060
                                )
                                
                                
                                40,803Accounts
      payable
                                
                                
                                2,161,325
                                
                                
                                
                                1,243,817
                                
                                
                                
                                373,381Accrued
      expenses
                                
                                
                                1,044,447
                                
                                
                                
                                (2,037,794
                                )
                                
                                
                                (902,185
                                )Net
      cash provided by operating activities
                                
                                
                                39,554,538
                                
                                
                                
                                1,372,287
                                
                                
                                
                                16,087,318Investing
      activitiesAdditions
      to property and equipment
                                
                                
                                (74,053
                                )
                                
                                
                                (132,371
                                )
                                
                                
                                (8,486,055
                                )Additions
      to natural gas and oil properties
                                
                                
                                (18,174,285
                                )
                                
                                
                                (12,821,192
                                )
                                
                                
                                (28,896,671
                                )Acquisitions
      of natural gas and oil properties
                                
                                
                                (100,742,893
                                )
                                
                                
                                (3,649,702
                                )
                                
                                
                                —Deposits
      and prepayments of natural gas and oil properties
                                
                                
                                (548,271
                                )
                                
                                
                                (9,805,460
                                )
                                
                                
                                —Net
      cash used in investing activities
                                
                                
                                (119,539,502
                                )
                                
                                
                                (26,408,725
                                )
                                
                                
                                (37,382,726
                                )Financing
      activitiesProceeds
      from borrowings
                                
                                
                                340,300,000
                                
                                
                                
                                126,200,000
                                
                                
                                
                                21,360,000Repayment
      of debt
                                
                                
                                (242,700,000
                                )
                                
                                
                                (182,867,500
                                )
                                
                                
                                —Proceeds
      from sale of initial public offering units, net
                                
                                
                                (54,191
                                )
                                
                                
                                89,946,916
                                
                                
                                
                                —Proceeds
      from private placement units
                                
                                
                                —
                                
                                
                                
                                41,220,000
                                
                                
                                
                                —Distributions
      to members
                                
                                
                                (20,128,990
                                )
                                
                                
                                (46,846,423
                                )
                                
                                
                                (1,375,104
                                )Financing
      costs
                                
                                
                                (302,563
                                )
                                
                                
                                (1,237,948
                                )
                                
                                
                                —Purchase
      of units for issuance as unit-based compensation
                                
                                
                                (236,239
                                )
                                
                                
                                —
                                
                                
                                
                                —Net
      cash provided by financing activities
                                
                                
                                76,878,017
                                
                                
                                
                                26,415,045
                                
                                
                                
                                19,984,896Net
      increase (decrease) in cash and cash equivalents
                                
                                
                                (3,106,947
                                )
                                
                                
                                1,378,607
                                
                                
                                
                                (1,310,512
                                )Cash and cash
      equivalents, beginning of year
                                
                                
                                3,109,563
                                
                                
                                
                                1,730,956
                                
                                
                                
                                3,041,468Cash and cash
      equivalents, end of year
                                
                                $
                                2,616
                                
                                
                                $
                                3,109,563
                                
                                
                                $
                                1,730,956Supplemental
      cash flow information:Cash
      paid for interest
                                
                                $
                                5,039,665
                                
                                
                                $
                                8,839,169
                                
                                
                                $
                                7,233,549Non-cash
      financing and investing activities:Asset
      retirement obligations
                                
                                $
                                1,882,397
                                
                                
                                $
                                177,153
                                
                                
                                $
                                187,638Derivative
      assets assumed in acquisition of natural gas and oil
      properties
                                
                                $
                                2,467,573
                                
                                
                                $
                                —
                                
                                
                                $
                                —Initial
      contribution of assets
                                
                                $
                                —
                                
                                
                                $
                                3,289,055
                                
                                
                                $
                                —Issuance
      of common units for acquisition of natural gas and oil
      properties
                                
                                $
                                21,360,000
                                
                                
                                $
                                —
                                
                                
                                $
                                —Transfer
      of deposit for acquisition of natural gas and oil
    properties
                                
                                $
                                7,830,000
                                
                                
                                $
                                —
                                
                                
                                $
                                —


See
accompanying notes to consolidated financial statements.







62
 Table of Contents


Vanguard Natural Resources, LLC and Subsidiaries


Consolidated
Statements of Other Comprehensive Income (Loss)


For
the Years Ended December 31,





Vanguard
                
                
                Vanguard
      Predecessor2008
                
                
                2007
                
                
                2006Net
      income (loss)
                
                $
                (3,751,348
                )
                
                $
                2,649,308
                
                
                $
                26,554,846Net income (losses) from
      derivative contracts:Unrealized mark-to-market gains
      (losses) arising during the period
                
                
                2,747,150
                
                
                
                (9,644,224
                )
                
                
                —Reclassification adjustments for
      settlements
                
                
                (492,923
                )
                
                
                (414,724
                )
                
                
                —Other comprehensive income
      (loss)
                
                
                2,254,227
                
                
                
                (10,058,948
                )
                
                
                —Comprehensive
      income (loss)
                
                $
                (1,497,121
                )
                
                $
                (7,409,640
                )
                
                $
                26,554,846







See
accompanying notes to consolidated financial statements.













63
 Table of Contents
 Vanguard Natural Resources, LLC and Subsidiaries
 Notes
to Consolidated Financial Statements
 December 31,
2008







Description of the
Business:




Vanguard
Natural Resources, LLC is a publicly traded limited liability company focused on
the acquisition and development of mature, long-lived natural gas and oil
properties in the United States. Through our operating subsidiaries, we own
properties in the southern portion of the Appalachian Basin, primarily in
southeast Kentucky and northeast Tennessee, in the Permian Basin, primarily in
west Texas and southeastern New Mexico, and in south Texas.




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




We were
formed in October 2006 and effective January 5, 2007, Vanguard Natural
Gas, LLC (formerly Nami Holding Company, LLC) was separated into our operating
subsidiary and Vinland Energy Eastern, LLC (“Vinland”). As part of the
separation, we retained all of our Predecessor’s proved producing wells and
associated reserves. We also retained 40% of our Predecessor’s working interest
in the known producing horizons in approximately 95,000 gross undeveloped acres
and a contract right to receive approximately 99% of the net proceeds from the
sale of production from certain producing gas and oil wells. In the separation,
Vinland was conveyed the remaining 60% of our Predecessor’s working interest in
the known producing horizons in this acreage, and 100% of our Predecessor’s
working interest in depths above and 100 feet below our known producing
horizons. Vinland operates all of our existing wells in Appalachia and all of
the wells that we drilled in Appalachia. We refer to these events as the
“Restructuring.”




In
October 2007, we completed our initial public offering (“IPO”) of 5.25
million units representing limited liability interests in VNR at $19.00 per unit
for net proceeds of $92.8 million after deducting underwriting discounts and
fees of $7.0 million. In addition, we incurred offering costs of $2.8 million in
connection with the IPO. The proceeds were used to reduce indebtedness under our
Credit Facility by $80.0 million and the balance was used for the payment of
accrued distributions to pre-IPO unitholders and the payment of a deferred swap
obligation.





1.   
Summary of Significant Accounting Policies





(a)
            Basis
      of Presentation and Principles of
Consolidation:





The
consolidated financial statements as of and for the years ended
December 31, 2008 and 2007 include the accounts of VNR and its wholly owned
subsidiaries. In conjunction with the Restructuring, Nami Resources Company, LLC
conveyed its assets to Vinland or TEC as appropriate and as of January 5, 2007
is not a wholly-owned subsidiary of VNG and therefore is not consolidated in
these consolidated financial statements.  The consolidated financial
statements as of and for the year ended December 31, 2006 are based on
the annual audited financial statements of VNG prior to the Restructuring. 
As such, these periods are labeled Vanguard Predecessor and are separated from
VNR financial data by a bold black line.




Our
consolidated financial statements are prepared in accordance with
U.S. generally accepted accounting principles and include the accounts of
all subsidiaries after the elimination of all significant intercompany accounts
and transactions.  Additionally, our financial statements for prior periods
include reclassifications that were made to conform to the current period
presentation. Those reclassifications did not impact our reported net income or
member’s equity.




(b)
            Recently
      Adopted Accounting Pronouncements:




In
September 2006, the Financial Accounting Standards Board (FASB) issued Statement
of Financial Accounting Standards No. 157 “Fair Value Measurements”
(“SFAS 157”). SFAS 157 introduces a framework for measuring fair value and
expands required disclosure about fair value measurements of assets and
liabilities. On February 6, 2008, the FASB issued a final FASB Staff Position
(“FSP”) No. FAS 157-b, “Effective Date of FASB Statement No. 157.” This FSP
delays the effective date of SFAS 157 for all non-financial assets and
non-financial liabilities, except those that are recognized or disclosed at fair
value in the financial statements on a recurring basis. In addition, the FSP
removes certain leasing transactions from the scope of SFAS 157. The effective
date of SFAS 157 for non-financial assets and non-financial liabilities has been
delayed by one year to fiscal years beginning after November 15, 2008 and
interim periods within those fiscal years. SFAS 157 for financial assets and
liabilities is effective for fiscal years beginning after November 15, 2007, and
the Company prospectively adopted the standard for those assets and liabilities
as of January 1, 2008. In adopting SFAS 157, the Company determined that the
impact of these additional assumptions on fair value measurements did not have




64
 Table of Contents




a
material effect on financial position or results of operations. The Company is
still assessing the potential impact of implementation in 2009 of those portions
of the guidance for which the effective date has been deferred by the
FASB.





In
February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial
Assets and Financial Liabilities, including an amendment of FASB Statement No.
115”(“SFAS
159”), which permits companies to choose, at specified dates, to measure certain
eligible financial instruments at fair value. The objective of SFAS 159 is to
reduce volatility in preparer reporting that may be caused as a result of
measuring related financial assets and liabilities differently and to expand the
use of fair value measurements. The provisions of SFAS 159 apply only to
entities that elect to use the fair value option. Additional disclosures are
also required 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 choose to adopt
early. At the effective date, companies may elect the fair value option for
eligible items that exist at that date, and the effect of the first
remeasurement to fair value must be reported as a cumulative-effect adjustment
to the opening balance of retained earnings. Effective January 1, 2008, the
Company adopted SFAS 159. Because the Company did not elect to apply the
provisions of SFAS 159 to any eligible financial instrument, the adoption did
not affect the consolidated financial statements.





(c)
            New
      Pronouncements Issued But Not Yet
Adopted:




In
December 2007, the FASB issued SFAS No. 141 (revised 2007), “Business Combinations”
(“SFAS 141(R)”), which replaces FASB Statement No. 141. SFAS 141(R) establishes
principles and requirements for how an acquirer recognizes and measures in its
financial statements the identifiable assets acquired, the liabilities assumed,
any non-controlling interest in the acquiree and the goodwill acquired. The
Statement also establishes disclosure requirements that will enable users to
evaluate the nature and financial effects of the business combination. SFAS
141(R) is effective for acquisitions that occur in an entity’s fiscal year that
begins after December 15, 2008, which will be our fiscal year 2009. The impact,
if any, on the consolidated financial statements will depend on the nature and
size of business combinations that we consummate after the effective
date.





In
December 2007, the FASB issued SFAS No. 160, “Non-controlling Interests in
Consolidated Financial Statements—an amendment of ARB No. 51” (“SFAS
160”). SFAS 160 requires that accounting and reporting for minority interests
will be recharacterized as non-controlling interests and classified as a
component of equity. SFAS 160 also establishes reporting requirements that
provide sufficient disclosures that clearly identify and distinguish between the
interests of the parent and the interests of the non-controlling
owners. SFAS 160 applies to all entities that prepare consolidated
financial statements, except not-for-profit organizations, but will affect only
those entities that have an outstanding non-controlling interest in one or more
subsidiaries or that deconsolidate a subsidiary. This statement is effective as
of the beginning of an entity’s first fiscal year beginning after December 15,
2008, which will be our fiscal year 2009. Based upon the December 31, 2008
balance sheet, SFAS 160 would have no impact on the consolidated financial
statements.





In March
2008, the FASB issued SFAS No. 161, “Disclosures about Derivative
Instruments and Hedging Activities” (“SFAS 161”). SFAS 161 is intended to
improve financial reporting about derivative instruments and hedging activities
by requiring enhanced disclosures to enable investors to better understand their
effects on an entity’s financial position, financial performance, and cash
flows. SFAS 161 achieves these improvements by requiring disclosure of the fair
values of derivative instruments and their gains and losses in a tabular format.
It also provides more information about an entity’s liquidity by requiring
disclosure of derivative features that are credit risk-related. Finally, it
requires cross-referencing within footnotes to enable financial statement users
to locate important information about derivative instruments. SFAS 161 is
effective for financial statements issued for fiscal years and interim periods
beginning after November 15, 2008, with early application encouraged. We are
currently evaluating the impact of adopting SFAS161on our consolidated financial
statements.





In
December 2008, the Securities and Exchange Commission or “SEC” published a
Final Rule, “Modernization of
Oil and Gas Reporting.”The new rule permits the use of new technologies
to determine proved reserves if those technologies have been demonstrated to
lead to reliable conclusions about reserves volumes. The new requirements also
will allow companies to disclose their probable and possible reserves to
investors. In addition, the new disclosure requirements require companies to:
(a) report the
independence and qualifications of its reserves preparer or auditor; (b) file reports when a third
party is relied upon to prepare reserves estimates or conducts a reserves audit;
and (c) report oil and
gas reserves using an average price based upon the prior 12-month period rather
than year-end prices. The use of average prices will affect future impairment
and depletion calculations. The new disclosure requirements are effective for
annual reports on Forms 10-K for fiscal years ending on or after
December 31, 2009. A company may not apply the new rules to disclosures in
quarterly reports prior to the first annual report in which the revised
disclosures are required. The Company has not yet determined the impact of this
Final Rule, which will vary depending on changes in commodity prices, on its
disclosures, financial position or results of operations.




65
 Table of Contents




(d)
            Cash
      Equivalents:




The
Company considers all highly liquid short-term investments with original
maturities of three months or less to be cash equivalents.




(e)
            Accounts
      Receivable and Allowance for Doubtful
      Accounts:





Accounts
receivable are customer obligations due under normal trade terms and are
presented on the consolidated balance sheets net of allowances for doubtful
accounts. We establish provisions for losses on accounts receivable if we
determine that we will not collect all or part of the outstanding balance. We
regularly review collectibility and establish or adjust our allowance as
necessary using the specific identification method.




(f)
            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. Inventories are
included in other current assets in the accompanying consolidated balance
sheets.


(g)
            Property
      and Equipment:





Property
and equipment is recorded at cost. Major property additions, replacements and
betterments are capitalized, while maintenance and repairs that do not extend
the useful life of an asset are expensed as incurred. Depreciation is recorded
using the straight-line method over the respective estimated useful lives of our
assets.




The
estimated useful lives of our property and equipment are as
follows:




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




Depreciation
expense for the years ended December 31, 2008 and 2007 was $56,283 and $36,539,
respectively. Our Predecessor’s consolidated statement of operations included
depreciation expense in the amount of $693,266 for the year ended
December 31, 2006.




(h)
            Natural
      Gas and Oil Properties:





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




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




Capitalized
costs are limited to a ceiling based on the present value of future net revenues
using end of period spot prices discounted at 10%, plus the lower of cost or
fair market value of unproved properties. If the ceiling is not greater than or
equal to the total capitalized costs, we are required to write down capitalized
costs to the ceiling. We perform this ceiling test calculation each quarter. Any
required write downs are included in the consolidated statements of operations
as an impairment charge. Ceiling test calculations include the effects of the
portion of natural gas and oil derivative contracts that have been recorded in
other




66
 Table of Contents




comprehensive
income. We recorded a non-cash ceiling test impairment of natural gas and oil
properties for the year ended December 31, 2008 of $58.9 million as a result of
a decline in natural gas and oil prices at the measurement date.  This
impairment was calculated based on prices of $5.71 per MMBtu for natural gas and
$41.00 per barrel of crude oil.  No ceiling test impairment was
required during 2007 or 2006.




When we
sell or convey interests in natural gas and oil properties, they reduce natural
gas and oil reserves for the amount attributable to the sold or conveyed
interest. We do not recognize a gain or loss on sales of natural gas and oil
properties, unless those sales would significantly alter the relationship
between capitalized costs and proved reserves. Sales proceeds on insignificant
sales are treated as an adjustment to the cost of the properties.




(i)
            Asset
      Retirement Obligations:




Under
SFAS No. 143, “Accounting
for Asset Retirement Obligations,” we record a liability for asset
retirement obligations at fair value in the period in which the liability is
incurred if a reasonable estimate of fair value can be made. The associated
asset retirement cost is capitalized as part of the carrying amount of the
long-lived asset. Subsequently, the asset retirement cost is allocated to
expense using a systematic and rational method over the assets useful life. Our
recognized asset retirement obligation exclusively relates to the plugging and
abandonment of natural gas and oil wells. Management periodically reviews the
estimate of the timing of well abandonments as well as the estimated plugging
and abandonment costs, which are discounted at the credit adjusted risk free
rate.  These retirement costs are recorded as a long-term liability on the
consolidated balance sheet with an offsetting increase in natural gas and oil
properties. An ongoing accretion expense is recognized for changes in the value
of the liability as a result of the passage of time, which we record in
depreciation, depletion, amortization and accretion expense in the consolidated
statements of operations.


(j)
            Impairment
      of Long-Lived Assets:





We
evaluate the carrying value of long-lived assets, other than investments in
natural gas and oil properties, when events or changes in circumstances indicate
that the carrying value of such assets may not be recoverable. For property and
equipment used in operations, the determination of impairment is based upon
expectations of undiscounted future cash flows, before interest, of the related
asset. If the carrying value of the asset exceeds the undiscounted future cash
flows, the impairment would be computed as the difference between the carrying
value of the asset and the fair value.


(k)
            Revenue
      Recognition and Gas Imbalances:





We apply
the sales method of accounting for natural gas and oil revenue. Under this
method, revenues are recognized based on the actual volume of natural gas and
oil sold to customers, net of any royalty interests owed on the sold product. In
the movement of natural gas, it is common for differences to arise between the
volume of gas contracted or nominated, and the volume of gas actually received
or delivered. These variances or imbalances, are the result of certain
attributes of the natural gas commodity and the industry itself. Consequently,
the credit given by a pipeline for volumes received from producers may be
different than volumes actually delivered by a pipeline. When all necessary
information, such as the final pipeline statement for receipts and deliveries
are available, the imbalances are resolved and adjustments to the trade accounts
receivable or trade accounts payable is recorded as appropriate. The
amounts of imbalances were not material at December 31, 2008 and
2007.





(l)
            Concentration
      of Credit Risk:





Financial
instruments that potentially subject us to concentrations of credit risk consist
principally of cash and cash equivalents, accounts receivable and derivative
contracts. We control our exposure to credit risk associated with these
instruments by (i) placing our assets and other financial interests with
credit-worthy financial institutions, (ii) maintaining policies over credit
extension that include the evaluation of customers’ financial condition and
monitoring payment history, although we do not have collateral requirements and
(iii) netting derivative assets and liabilities for counterparties where we have
a legal right of offset.


At
December 31, 2008 and 2007, the cash and cash equivalents are concentrated
in three financial institutions. We periodically assess the financial condition
of these institutions and believe that any possible credit risk is
minimal.





The
following purchasers accounted for 10% or more of the Company’s natural gas and
oil sales for the years ended December 31:




67
 Table of Contents





2008
                
                
                2007
                
                
                2006Seminole
      Energy Services
                
                
                52
                %
                
                
                —
                
                
                
                —North
      American Energy Corporation
                
                
                —
                
                
                
                41
                %
                
                
                32
                %Osram
      Sylvania, Inc.
                
                
                15
                %
                
                
                16
                %
                
                
                13
                %BP
      Energy Company
                
                
                10
                %
                
                
                11
                %
                
                
                10
                %Dominion
      Field Services, Inc.
                
                
                —
                
                
                
                13
                %
                
                
                13
                %Eagle
      Energy Partners, LLC
                
                
                —
                
                
                
                11
                %
                
                
                7
                %








This
concentration of customers may impact the overall exposure to credit risk in
that the customers are in the energy industry and they may be similarly affected
by changes in economic or other conditions.





(m)
            Use
      of Estimates:





The
preparation of financial statements in conformity with accounting principles
generally accepted in the Unites States of America requires management to make
estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the date of
the financial statements and the reported amounts of revenues and expenses
during the reporting period. The most significant estimates pertain to proved
natural gas and oil reserves and related cash flow estimates used in impairment
tests of natural gas and oil properties, the fair value of derivative contracts
and asset retirement obligations, accrued natural gas and oil revenues and
expenses, as well as estimates of expenses related to depreciation, depletion,
amortization and accretion.  Actual results could differ from those
estimates.





(n)
            Price
      Risk Management Activities:





We have
entered into derivative contracts with counterparties that are lenders under our
reserve-based credit facility, Citibank N.A., BNP Paribas, The Bank of Nova
Scotia and Wachovia Bank, N.A., to hedge price risk associated with a portion of
our natural gas and oil production. While it is never management’s intention to
hold or issue derivative instruments for speculative trading purposes,
conditions sometimes arise where actual production is less than estimated which
has, and could, result in overhedged volumes. Under fixed-priced commodity swap
agreements, the Company receives a fixed price on a notional quantity in
exchange for paying a variable price based on a market index, such as the
Columbia Gas Appalachian Index (‘TECO Index”), Henry Hub or Houston Ship Channel
for natural gas production and the West Texas Intermediate Light Sweet for oil
production. Under put option agreements, we pay the counterparty an option
premium, equal to the fair value of the option at the purchase date. At
settlement date we receive the excess, if any, of the fixed floor over floating
rate. Under collar contracts, we pay the counterparty if the market price is
above the ceiling price and the counterparty pays us if the market price is
below the floor price on a notional quantity. The collars and put options for
natural gas are settled based on the NYMEX price for natural gas at Henry Hub or
Houston Ship Channel.





Under
Statement of Financial Accounting Standards No. 133 “Accounting for Derivative
Instruments and Hedging Activities,” (“SFAS 133”), all derivative
instruments are recorded on the consolidated balance sheets at fair value as
either short-term or long-term assets or liabilities based on their anticipated
settlement date.  We net derivative assets and liabilities for
counterparties where we have a legal right of offset.  Changes in the
derivatives’ fair value are recognized currently in earnings unless specific
hedge accounting criteria are met.  For qualifying cash flow hedges,
the unrealized gain or loss on the derivative is deferred in accumulated other
comprehensive income (loss) in the equity section of the consolidated balance
sheets to the extent the hedge is effective.  Gains and losses on cash
flow hedges  included in accumulated other comprehensive income (loss)
are reclassified to gains (losses) on commodity cash flow hedges in the period
that the related production is delivered.  The unrealized gains
(losses) on derivative contracts that do not qualify for hedge accounting
treatment are recorded as gains (losses) on other commodity derivative contracts
in the Consolidated Statements of Operations.





In
connection with preparing our quarterly report for third quarter 2008 and
discussion with BDO Seidman, LLP, the Company’s new independent registered
public accounting firm, management of the Company and the Audit Committee of its
Board of Directors concluded that the contemporaneous formal documentation it
had prepared to support its initial hedge designations and subsequent
assessments for ineffectiveness in connection with the Company’s natural gas and
oil hedging program in 2008 did not meet the technical requirements to qualify
for cash flow hedge accounting treatment in accordance with SFAS 133. The
primary reasons for this determination were that the formal hedge documentation
lacked specificity of the hedged cash flow and the quantitative subsequent
assessments for ineffectiveness were insufficient.  Therefore, the
cash flow designations failed to meet hedge documentation requirements for cash
flow hedge accounting treatment.  In addition, the natural gas
derivative swap contracts entered into in 2007 were de-designated as cash flow
hedges in the first quarter of 2008 due to an overhedged position in natural gas
which




68
 Table of Contents


made them
ineffective. As a result, the Company now recognizes changes in its derivatives’
fair values in current earnings under gains (losses) on other commodity
derivative contracts. In addition, the net derivative loss at December 31, 2007
related to the de-designated natural gas derivate swap contracts entered into in
2007 is reported in accumulated other comprehensive income until the month in
which the transactions settle, at which time it is recognized as gains (losses)
on commodity cash flow hedges.





(o)
            Income
      Taxes:





The
Company is treated as a partnership for federal and state income tax
purposes.  As such, it is not a taxable entity and does not directly pay
federal and state income tax. Its taxable income or loss, which may vary
substantially from the net income or net loss reported in the consolidated
statements of operations, is included in the federal and state income tax
returns of each unitholder.  Accordingly, no recognition has been given to
federal and state income taxes for the operations of the Company.  The
aggregate difference in the basis of net assets for financial and tax reporting
purposes cannot be readily determined as the Company does not have access to
information about each unitholders’ tax attributes in the Company. However with
respect to the Company, the Company’s book basis in its net assets exceeded the
Company’s net tax basis by $54.7 million at December 31, 2008.





Legal
entities that conduct business in Texas are subject to the Revised Texas
Franchise Tax, including previously non-taxable entities such as limited
partnerships and limited liability partnerships. The tax is assessed on Texas
sourced taxable margin which is defined as the lesser of (i) 70% of total
revenue or (ii) total revenue less (a) cost of goods sold or
(b) compensation and benefits. Although the Revised Texas Franchise Tax is
not an income tax, it has the characteristics of an income tax since it is
determined by applying a tax rate to a base that considers both revenues and
expenses. The Company recorded a current tax liability of $0.1 million and a
deferred tax liability of $0.2 million during the year ended
December 31, 2008, respectively. The charges of $0.1 million and $0.2
million are included on our consolidated statements of operations for the year
ended December 31, 2008, respectively, as a component of production and
other taxes. The Company had no Texas sourced margin tax prior to
2008.





2.   
Acquisitions




On
December 21, 2007, we entered into a Purchase and Sale Agreement with the Apache
Corporation for the purchase of certain oil and natural gas properties located
in ten separate fields in the Permian Basin of west Texas and southeastern New
Mexico. The purchase price for said assets was $78.3 million with an effective
date of October 1, 2007. We completed this acquisition on January 31, 2008 for
an adjusted purchase price of $73.4 million, subject to customary post closing
adjustments. The post closing adjustments reduced the final purchase price to
$71.5 million and included a purchase price adjustment of $6.8 million for the
cash flow from the acquired properties for the period between the effective
date, October 1, 2007, and the final settlement date. The purchase price
included a payment of $7.8 million paid by us to the seller in December 2007 and
this amount is reported in non-current deposits in our consolidated balance
sheet at December 31, 2007. As part of this acquisition, we assumed fixed-price
oil swaps covering approximately 90% of the estimated proved developed producing
oil reserves through 2011 at a weighted average price of $87.29. The fair value
of these fixed-price oil swaps was a liability of $1.1million at January 31,
2008. This acquisition was funded with borrowings under our existing
reserve-based credit facility.
 
 On July
18, 2008, we entered into a Purchase and Sale Agreement with Segundo Navarro
Drilling, Ltd., a wholly owned subsidiary of the Lewis Energy Group, for the
acquisition of certain natural gas and oil properties located in the Dos
Hermanos Field in Webb County, Texas. The purchase price for said assets was
$53.4 million with an effective date of June 1, 2008. We completed this
acquisition on July 28, 2008 for an adjusted purchase price of $51.4 million,
subject to customary post-closing adjustments to be determined. This acquisition
was funded with $30.0 million of borrowings under our reserve-based credit
facility and through the issuance of 1,350,873 common units of the Company
valued at $21.4 million. Upon closing this transaction, we assumed natural gas
swaps and collars based on Houston Ship Channel pricing for approximately 85% of
the estimated gas production from existing producing wells for the period
beginning July 2008 through December 2011 which had a fair value of $3.6 million
on July 28, 2008.
 
 The
following unaudited pro forma results for the years ended December 31, 2008 and
2007 show the effect on the Company’s consolidated results of operations as if
the January 2008 acquisition and July 2008 acquisition had occurred on January
1, 2008 and 2007. The pro forma results for the 2008 and 2007 periods presented
are the results of combining the statement of operations for the Company with
the revenues and direct operating expenses of the oil and gas properties
acquired adjusted for (1) assumption of asset retirement obligations and
accretion expense for the properties acquired, (2) depletion expense applied to
the adjusted basis of the properties acquired using the purchase method of
accounting, (3) impairment of natural gas and oil properties, (4)interest
expense on added borrowings necessary to finance the acquisition, and (5) the
impact of common units issued to partially finance the July 2008 acquisition.
The pro forma information is based upon numerous assumptions, and is not
necessarily indicative of future results of operations:


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Year Ended December 31,2008
                  Pro
      forma
                
                
                2007
                  Pro
      forma(in thousands,
      except per unit amounts)(unaudited)Total
      revenues
                
                $
                109,919
                
                
                $
                60,774Net
      income
                
                $
                1,893
                
                
                $
                6,321Net
      income per unit:Common & Class B units – basic
                
                $
                0.15
                
                
                $
                0.77Common &
      Class B units – diluted
                
                $
                0.15
                
                
                $
                0.77








3.   
Accounts Receivable and Allowance for Doubtful Accounts




We
established an approximate $1.0 million provision for a loss on the entire
amount due from a customer which filed for protection under Chapter 11 of the
Bankruptcy Code in May 2007.  The account receivable was due from oil
sales through December 2006 at which time we ceased selling oil to the
customer. As the amount of any potential recovery is uncertain, we elected to
reserve the entire balance and it is reflected as bad debt expense on our
consolidated statement of operations for the year ended December 31, 2007.
We began selling our oil production to a new customer beginning in
March 2007.





4.   
Credit Facilities and Long-Term Debt




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







Description
                      Interest Rate
                      Maturity Date
                      2008
                      
                      2007Senior
      secured reserve-based credit facility
                      Variable
                      March
      31, 2011
                      $
                      135,000,000
                      
                      $
                      37,400,000Total
                      
                      
                      $
                      135,000,000
                      
                      $
                      37,400,000





Senior
Secured Reserve-Based Credit Facility




In
January 2007, the Company entered into a four-year revolving reserve-based
credit facility (“reserve-based credit facility”) with Citibank, N.A. and BNP
Paribas. All of our Predecessor’s outstanding debt was repaid with borrowings
under this reserve-based credit facility, including an early prepayment penalty
of $2.5 million. The available credit line (“borrowing base”) is subject to
adjustment from time to time but not less than on a semi-annual basis based on
the projected discounted present value (as determined by independent petroleum
engineers) of estimated future net cash flows from certain proved natural gas
and oil reserves of the Company. The initial borrowing base was set at $115.5
million and is secured by a first lien security interest in all of the Company’s
natural gas and oil properties. However, the borrowing base was subject to $1.0
million reductions per month starting on July 1, 2007 through November 1, 2007,
which resulted in a borrowing base of $110.5 million as reaffirmed in November
2007 pursuant to the semi-annual borrowing base redetermination. We applied
$80.0 million of the net proceeds from our IPO in October 2007 to reduce our
indebtedness under the reserve-based credit facility. In February 2008, our
reserve-based credit facility was amended and restated to extend the maturity
from January 3, 2011 to March 31, 2011, increase the maximum facility amount
from $200.0 million to $400.0 million, increase our borrowing base from $110.5
million to $150.0 million and add two additional financial institutions as
lenders, Wachovia Bank, N.A. and The Bank of Nova Scotia. Additional borrowings
were made in January 2008 pursuant to the acquisition of natural gas and oil
properties in the Permian Basin and in July 2008 an additional $30.0 million was
borrowed to fund a portion of the cash consideration paid in the south Texas
acquisition. In May 2008, our reserve-based credit facility was amended in
response to a potential acquisition that ultimately did not occur. As a result,
none of the provisions included in this amendment went into effect. In October
2008, we amended our reserve-based credit facility, which set our borrowing base
under the facility at $175.0 million pursuant to our semi-annual redetermination
and added a new lender, Compass Bank. As a result, indebtedness under the
reserve-based credit facility totaled $135.0 million at December 31, 2008. In
February 2009 our reserve-based credit facility was amended. See Note 12. Subsequent Events for further
discussion.




Interest
rates under the reserve-based credit facility are based on Euro-Dollars (LIBOR)
or ABR (Prime) indications, plus a




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margin.
Pursuant to the October 2008 reserve-based credit facility amendment our
borrowing base utilization grid is as follows:




Borrowing Base Utilization Grid




Borrowing
      Base Utilization Percentage
                  
                  <33%
                  
                  
                  >33%
      <66%
                  
                  
                  >66% <85%
                  
                  
                  >85%Eurodollar
      Loans
                  
                  
                  1.500
                  %
                  
                  
                  1.750
                  %
                  
                  
                  2.000
                  %
                  
                  
                  2.125
                  %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 credit facility contains a number of customary covenants that
require us to maintain certain financial ratios, limit our ability to incur
additional debt, sell assets, create liens, or make certain distributions.
Additionally, our reserve-based credit facility stipulates that a change of
control is not permitted, which includes (1) an acquisition of ownership,
directly or indirectly, beneficially or of record, by any person or group
(within the meaning of the Securities Exchange Act of 1934 and the rules of the
SEC) of equity interests representing more than 25% of the aggregate ordinary
voting power represented by our issued and outstanding equity interests other
than by Majeed S. Nami or his affiliates, or (2) the replacement of a majority
of our directors by persons not approved by our board of directors. At
December 31, 2008, we were in compliance with our debt
covenants.





Our
reserve-based credit facility required us to enter into a commodity price hedge
position establishing certain minimum fixed prices for anticipated future
production equal to approximately 84% of the projected production from proved
developed producing reserves from the second half of 2007 through 2011. Also,
our reserve-based credit facility required that certain production put option
contracts for the years 2007, 2008 and 2009 be put in place to create a price
floor for anticipated production from new wells drilled. 
See  Note 5. Price
Risk Management Activities for further discussion.





5.   
Price Risk Management Activities





We have
entered into derivative contracts with counterparties that are lenders under our
reserve-based credit facility, Citibank N.A., BNP Paribas, The Bank of Nova
Scotia and Wachovia Bank, N.A., to hedge price risk associated with a portion of
our natural gas and oil production. While it is never management’s intention to
hold or issue derivative instruments for speculative trading purposes,
conditions sometimes arise where actual production is less than estimated which
has, and could, result in overhedged volumes. Under fixed-priced commodity swap
agreements, the Company receives a fixed price on a notional quantity in
exchange for paying a variable price based on a market index, such as the
Columbia Gas Appalachian Index (‘TECO Index”), Henry Hub or Houston Ship Channel
for natural gas production and the West Texas Intermediate Light Sweet for oil
production. Under put option agreements, we pay the counterparty an option
premium, equal to the fair value of the option at the purchase date. At
settlement date we receive the excess, if any, of the fixed floor over floating
rate. Under collar contracts, we pay the counterparty if the market price is
above the ceiling price and the counterparty pays us if the market price is
below the floor price on a notional quantity. The collars and put options for
natural gas are settled based on the NYMEX price for natural gas at Henry Hub or
Houston Ship Channel.





Under
SFAS 133, all derivative instruments are recorded on the consolidated balance
sheets at fair value as either short-term or long-term assets or liabilities
based on their anticipated settlement date.  We net derivative assets
and liabilities for counterparties where we have a legal right of
offset.  Changes in the derivatives’ fair value are recognized
currently in earnings unless specific hedge accounting criteria are
met.  For qualifying cash flow hedges, the unrealized gain or loss on
the derivative is deferred in accumulated other comprehensive income (loss) in
the equity section of the consolidated balance sheets to the extent the hedge is
effective.  Gains and losses on cash flow hedges included in
accumulated other comprehensive income (loss) are reclassified to gains (losses)
on commodity cash flow hedges in the period that the related production is
delivered.  The unrealized gains (losses) on derivative contracts that
do not qualify for hedge accounting treatment are recorded as gains (losses) on
other commodity derivative contracts in the Consolidated Statements of
Operations.





On
January 3, 2007, our Predecessor’s natural gas price swaps were terminated,
which resulted in the Company incurring swap termination fees of $2.8 million
and an additional loss on derivative contracts of approximately $0.8 million
included in our consolidated statement of operations for the year ended December
31, 2007. New natural gas derivative contracts were put in place in conjunction
with entering into the reserve-based credit facility as described in Note 4.
Credit Facility and Long-Term
Debt. The Company paid $6.5 million for the put option contracts and
payments for the put option contracts and the swap termination fee were funded
with borrowings under the reserve-based credit facility. At our election, also
in January 2007, we entered into a NYMEX natural gas collar contract. In May
2007, we reset our 2007, 2008 and 2009 natural gas swaps at higher prices and
incurred a $7.3 million deferred swap payment obligation with the derivative
counterparty which accrued interest daily at 7.36% and was payable at




71
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the
earlier of five days after the closing of an equity issuance or November 1,
2007. The deferred swap obligation was paid in October 2007 using proceeds from
our IPO.





In
February 2008, as part of the Permian Basin acquisition, we assumed fixed-price
oil swaps covering approximately 90% of the estimated proved developed producing
oil production through 2011 at a weighted average price of $87.29. Also, in
February 2008, we sold calls (or set a ceiling price) which effectively collared
2,000,000 MMBtu of gas production in 2008 through 2009 which was previously only
subject to a put (or price floor), we reset the price on 2,387,640 MMBtu of
natural gas swaps settling in 2010 from $7.53 to $8.76 per MMBtu and we entered
into a 2012 fixed-price oil swap at $80.00 for 87% of our estimated proved
developed production. In April 2008, we reset the price on 800,000 MMBtu of
natural gas puts settling from May 1, 2008 to December 31, 2008 from $7.50 to
$9.00 per MMBtu at a cost to the Company of $0.3 million which was funded with
cash on hand. In July 2008, in connection with the south Texas acquisition, we
assumed natural gas swaps and collars based on Houston Ship Channel pricing for
approximately 85% of the estimated gas production from existing producing wells
for the period beginning July 2008 through December 2011.





In
November 2008, in connection with preparing our quarterly report for third
quarter 2008 and discussion with BDO Seidman, LLP, the Company’s new independent
registered public accounting firm, management of the Company and the Audit
Committee of its Board of Directors concluded that the contemporaneous formal
documentation it had prepared to support its initial hedge designations and
subsequent assessments for ineffectiveness in connection with the Company’s
natural gas and oil hedging program in 2008 did not meet the technical
requirements to qualify for cash flow hedge accounting treatment in accordance
with SFAS 133. The primary reasons for this determination were that the formal
hedge documentation lacked specificity of the hedged cash flow and the
quantitative subsequent assessments for ineffectiveness were
insufficient.  Therefore, the cash flow designations failed to meet
hedge documentation requirements for cash flow hedge accounting
treatment.  In addition, the natural gas derivative swap contracts
entered into in 2007 were de-designated as cash flow hedges in the first quarter
of 2008 due to an overhedged position in natural gas which made them
ineffective. As a result, the Company now recognizes changes in its derivatives’
fair values in current earnings under gains (losses) on other commodity
derivative contracts. In addition, the net derivative loss at December 31, 2007
related to the de-designated natural gas derivate swap contracts entered into in
2007 is reported in accumulated other comprehensive income until the month in
which the transactions settle, at which time it is recognized as gains (losses)
on commodity cash flow hedges.




At
December 31, 2008, the Company had open commodity derivative contracts covering
our anticipated future production as follows:


Swap
Agreements




Gas
                                                                
                                                                OilContract
      Period
                                                                MMBtu
                                                                
                                                                Weighted
                                                                  Average
                                                                  FixedPrice
                                                                
                                                                Bbls
                                                                
                                                                WTI
                                                                  Price2009
                                                                3,629,946
                                                                
                                                                $
                                                                9.42
                                                                
                                                                181,500
                                                                
                                                                $
                                                                87.232010
                                                                3,236,040
                                                                
                                                                $
                                                                9.10
                                                                
                                                                164,250
                                                                
                                                                $
                                                                85.652011
                                                                2,962,312
                                                                
                                                                $
                                                                7.82
                                                                
                                                                151,250
                                                                
                                                                $
                                                                85.502012
                                                                —
                                                                
                                                                $
                                                                —
                                                                
                                                                144,000
                                                                
                                                                $
                                                                80.00





Put Option
Contracts





Contract
      Period
                          Volume in MMBtu
                          
                          Purchased NYMEXPrice Floor2009
                          840,143
                          
                          $
                          7.50





Collars




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Gas
                        
                        
                        OilMMBtu
                        
                        Floor
                        
                        Ceiling
                        
                        
                        Bbls
                        
                        Floor
                        
                        CeilingProduction
      Period:2009
                        
                        
                        1,000,000
                        
                        
                        $
                        7.50
                        
                        
                        $
                        9.00
                        
                        
                        
                        36,500
                        
                        
                        $
                        100.00
                        
                        
                        $
                        127.002010
                        
                        
                        730,000
                        
                        
                        $
                        8.00
                        
                        
                        $
                        9.30
                        
                        
                        
                        —
                        
                        
                        $
                        —
                        
                        
                        $
                        —




In
February 2009, we liquidated our 2012 oil swap and entered into new natural gas
derivative contracts.  See Note 12. Subsequent Eventsfor
further discussion.





Interest Rate
Swaps





We enter
into interest rate swap agreements, which require exchanges of cash flows that
serve to synthetically convert a portion of our variable interest rate exposures
to fixed interest rates.





From
December 2007 through March 2008, we entered into interest rate swap agreements
which effectively fixed the LIBOR rate at 2.66 % to 3.88% on $60.0 million of
borrowings. In August 2008, we entered into two interest rate basis swaps which
changed the reset option from three month LIBOR to one month LIBOR on the total
$60.0 million of outstanding interest rate swaps. By doing so, the company
reduced its borrowing cost by 14 basis points on $20.0 million of borrowings for
a one year period starting September 10, 2008 and 12 basis points on $40.0
million of borrowings for a one year period starting October 31, 2008. As a
result of these two basis swaps, the company chose to de-designate the interest
rate swaps as cash flow hedges as the terms of the new contracts no longer
matched the terms of the original contracts, thus causing the interest rate
hedges to be ineffective. Beginning in the third quarter of 2008, the Company
recorded changes in the fair value of its interest rate derivatives in current
earnings under gains (losses) on interest rate derivative contracts. The net
unrealized gain at June 30, 2008 related to the de-designated cash flow hedges
is reported in accumulated other comprehensive income and later reclassified to
earnings in the month in which the transactions settle.





At
December 31, 2008, the Company had open interest rate derivative contracts as
follows:





Notional
                    Amount
                  
                  Fixed
                    Libor
                    RatesPeriod:January
      1, 2009 to December 10, 2010
                  
                  $
                  10,000,000
                  
                  1.50
                  %January
      1, 2009 to December 20, 2010
                  
                  $
                  10,000,000
                  
                  1.85
                  %January
      1, 2009 to January 31, 2011
                  
                  $
                  20,000,000
                  
                  3.00
                  %January
      1, 2009 to March 31, 2011
                  
                  $
                  20,000,000
                  
                  2.08
                  %January
      1, 2009 to December 10, 2012
                  
                  $
                  20,000,000
                  
                  3.35
                  %January
      1, 2009 to January 31, 2013
                  
                  $
                  20,000,000
                  
                  2.38
                  %January
      1, 2009 to September 10, 2009 (Basis Swap)
                  
                  $
                  20,000,000
                  
                  LIBOR
      1M vs. LIBOR 3MJanuary
      1, 2009 to October 31, 2009 (Basis Swap)
                  
                  $
                  40,000,000
                  
                  LIBOR
      1M vs. LIBOR 3M





6.   
Fair Value Measurements





As
discussed in Note 1. Summary of Significant Accounting Policies (b), we
prospectively adopted SFAS 157 for financial assets and financial liabilities.
SFAS 157 does not expand the use of fair value measurements, but rather,
provides a framework for consistent measurement of fair value for those assets
and liabilities already measured at fair value under other accounting
pronouncements. Certain specific fair value measurements, such as those related
to share-based compensation, are not included in the scope of SFAS 157.
Primarily, SFAS 157 is applicable to assets and liabilities related to financial
instruments, to some long-term investments and liabilities, to initial
valuations of assets and liabilities acquired in a business combination, and to
long-lived assets carried at fair value subsequent to an impairment
write down. It does not apply to natural gas and oil properties accounted
for under the full cost method, which are subject to impairment based on SEC
rules. SFAS 157 applies to assets and liabilities carried at fair value on the
consolidated balance sheet, as well as to supplemental fair value information
about financial instruments not carried at




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fair
value.





The
estimated fair values of the Company’s financial instruments closely approximate
the carrying amounts as discussed below:





Cash and cash equivalents, accounts
receivable, other current assets, accounts payable, payables to affiliates and
accrued expenses.The carrying amounts approximate fair value due to the
short maturity of these instruments.





Long-term debt.The carrying
amount of our reserve-based credit facility approximates fair value because our
current borrowing rate does not materially differ from market rates for similar
bank borrowings.





Certain
provisions of SFAS 157 have been deferred by the FASB. Accordingly, the Company
has not applied the provisions of SFAS 157 to those non-financial assets and
liabilities which are not measured at fair value on a non-recurring basis. This
includes asset retirement obligations, and any assets other than natural gas and
oil properties, for which an impairment write down is recorded during the
period. There have been no such asset impairments in the current
period.





The
Company has applied the provisions of SFAS 157 to assets and liabilities
measured at fair value on a recurring basis. This includes natural gas, oil and
interest rate derivatives contracts. SFAS 157 provides a definition of fair
value and a framework for measuring fair value, as well as expanding disclosures
regarding fair value measurements. The framework requires fair value measurement
techniques to include all significant assumptions that would be made by willing
participants in a market transaction. These assumptions include certain factors
not consistently provided for previously by those companies utilizing fair value
measurement; examples of such factors would include the company’s own credit
standing (when valuing liabilities) and the buyer’s risk premium. In adopting
SFAS 157, the Company determined that the impact of these additional assumptions
on fair value measurements did not have a material effect on financial position
or results of operations. The Company is still assessing the potential impact of
implementation in 2009 of those portions of the guidance for which the effective
date has been deferred by the FASB.





SFAS 157
defines fair value as the exchange price that would be received for an asset or
paid to transfer a liability (an exit price) in the principal or most
advantageous market for the asset or liability in an orderly transaction between
market participants on the measurement date. SFAS 157 provides a hierarchy of
fair value measurements, based on the inputs to the fair value estimation
process. It requires disclosure of fair values classified according to the
“levels” described below. The hierarchy is based on the reliability of the
inputs used in estimating fair value and requires an entity to maximize the use
of observable inputs and minimize the use of unobservable inputs when measuring
fair value. The framework for fair value measurement assumes that transparent
“observable” (Level 1) inputs generally provide the most reliable evidence of
fair value and should be used to measure fair value whenever available. The
classification of a fair value measurement is determined based on the lowest
level (with Level 3 as lowest) of significant input to the fair value estimation
process.





The
standard describes three levels of inputs that may be used to measure fair
value:


Level
      1
              Quoted
      prices for identical instruments in active markets.Level 
      2
              Quoted
      market prices for similar instruments in active markets; quoted prices for
      identical or similar instruments in markets that are not active; and
      model-derived valuations in which all significant inputs and significant
      value drivers are observable in active markets.Level 3
              Valuations
      derived from valuation techniques in which one or more significant inputs
      or significant value drivers are unobservable. Level 3 assets and
      liabilities generally include financial instruments whose value is
      determined using pricing models, discounted cash flow methodologies, or
      similar techniques, as well as instruments for which the determination of
      fair value requires significant management judgment or estimation or for
      which there is a lack of external corroboration as to the inputs
      used.





As
required by SFAS 157, financial assets and liabilities are classified based on
the lowest level of input that is significant to the fair value measurement. Our
assessment of the significance of a particular input to the fair value
measurement requires judgment, and may affect the valuation of the fair value of
assets and liabilities and their placement within the fair value hierarchy
levels. Our commodity derivative instruments consist of swaps and options. We
estimate the fair values of the swaps based on published forward commodity price
curves for the underlying commodities as of the date of the estimate. We
estimate the option value of the contract




74
 Table of Contents


floors
and ceilings using an option pricing model which takes into account market
volatility, market prices and contract parameters The discount rate used in the
discounted cash flow projections is based on published LIBOR rates, Eurodollar
futures rates and interest swap rates. In order to estimate the fair value of
our interest rate swaps, we use a yield curve based on money market rates and
interest rate swaps, extrapolate a forecast of future interest rates, estimate
each future cash flow, derive discount factors to value the fixed and floating
rate cash flows of each swap, and then discount to present value all known
(fixed) and forecasted (floating) swap cash flows. Curve building and
discounting techniques used to establish the theoretical market value of
interest bearing securities are based on readily available money market rates
and interest rate swap market data. To extrapolate future cash flows, discount
factors incorporating our counterparties’ and our credit standing are used to
discount future cash flows. The Company has classified the fair values of all
its derivative contracts as Level 2.





Financial
assets and financial liabilities measured at fair value on a recurring basis are
summarized below:





December 31, 2008Fair Value Measurements Using
                  
                  
                  Assets/LiabilitiesLevel
      1
                  
                  
                  Level
      2
                  
                  
                  Level
      3
                  
                  
                  at Fair valueAssets:Commodity
      derivative contracts
                  
                  $
                  —
                  
                  
                  $
                  37,932,369
                  
                  
                  $
                  —
                  
                  
                  $
                  37,932,369Total
      derivative instruments
                  
                  $
                  —
                  
                  
                  $
                  37,932,369
                  
                  
                  $
                  —
                  
                  
                  $
                  37,932,369Liabilities:Interest
      rate derivative contracts
                  
                  $
                  —
                  
                  
                  $
                  (2,799,911
                  )
                  
                  $
                  —
                  
                  
                  $
                  (2,799,911
                  )Total
      derivative instruments
                  
                  $
                  —
                  
                  
                  $
                  (2,799,911
                  )
                  
                  $
                  —
                  
                  
                  $
                  (2,799,911
                  )





7.   
      Asset Retirement Obligations





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




2008
                        
                        
                        2007Asset retirement obligation at January 1,
                        
                        $
                        189,711
                        
                        
                        $
                        —Liabilities
      added during the current period
                        
                        
                        1,882,397
                        
                        
                        
                        177,153Accretion
      expense
                        
                        
                        61,683
                        
                        
                        
                        12,558Asset
      retirement obligation at December 31,
                        
                        $
                        2,133,791
                        
                        
                        $
                        189,711




Accretion
expense for the years ended December 31, 2008, 2007 and 2006 was $61,683,
$12,558 and $18,307, respectively.


8.   
      Related Party Transactions





In
Appalachia, we rely on Vinland to execute our drilling program, operate our
wells and gather our natural gas. We reimburse Vinland $60 per well per month
(in addition to normal third party operating costs) for operating our current
natural gas and oil properties in Appalachia under a Management Services
Agreement (“MSA”) which costs are reflected in our lease operating
expenses.  Also, Vinland receives 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 or “AMI.”  This transportation fee only encompasses transporting
the natural gas to third party pipelines at which point additional
transportation fees to natural gas markets apply.  These transportation
fees are outlined under a Gathering and Compression Agreement (“GCA”) with
Vinland and are reflected in our lease operating expenses. For the years ended
December 31, 2008 and 2007, costs incurred under the MSA were $0.6 million
and $0.5 million, respectively and costs incurred under the GCA were $1.0
million and $1.2 million, respectively. In addition, for the year ended
December 31, 2007, Vinland reimbursed us for certain gas sales
contracts that were fixed at prices below market in the amount of $1.0 million
which is reflected in natural gas and oil sales. A payable of $2.6 million and
$3.8 million, respectively, is reflected on our December 31, 2008 and
December 31, 2007 consolidated balance sheets in connection with these
agreements and direct expenses incurred by Vinland related to the drilling of
new wells and operations of all of our existing wells in Appalachia. In
September 2008, the Company acquired certain natural gas and oil properties in
Appalachia from Vinland for a total purchase price of $4.0 million. The
consideration included $3.1 million in cash and $0.9 million reduction in
amounts previously due to Vanguard.




75
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9.   Commitments
      and Contingencies




The
Company is a defendant in a legal proceeding arising in the normal course of our
business. While the outcome and impact of such legal proceedings on the Company
cannot be predicted with certainty, management does not believe that it is
probable that the outcome of any action will have a material adverse effect on
the Company’s consolidated financial position, results of operations or cash
flow.




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




On
September 8, 2006, Asher filed a complaint in Kentucky state court
initiating an action styledAsher Land and Mineral, Ltd. v. Nami Resources Company, LLC, Bell Circuit
Court, Civil Action No. 06-CI-00417. In that action, Asher sought monetary
damages and court-ordered rescission of the leases. Before a responsive pleading
was filed, Asher voluntarily withdrew its complaint and dismissed the case. On
December 15, 2006, Asher filed a new action styledAsher Land and Mineral, Ltd. v.
Nami Resources Company, LLC, Bell Circuit Court, Civil Action
No. 06-CI-00566. In that action, Asher has made the same allegations as in
the prior suit and added a claim for an undetermined amount of punitive damages.
The parties have exchanged limited initial discovery requests.




On
August 29, 2007, Asher filed a motion to add additional defendants to the
action cited above, including Vanguard Natural Resources, LLC, Vanguard Natural
Gas, LLC and Trust Energy Company, LLC. The Company has filed several motions to
be dismissed from this action but to date is still a named defendant in this
case. Since that time, no discovery has been sought from the Company by Asher.
We have retained separate counsel to represent us in this case as it progresses
and intend to continue to vigorously defend the action.




We
received a contract right to receive approximately 99% of the net proceeds from
the sale of production from certain producing oil and gas wells located within
the Asher lease, which accounted for approximately 2.6% of our estimated proved
reserves as of December 31, 2008. We did not receive an assignment of any
working interest in the Asher lease. The Asher lease and the litigation related
thereto were retained by Nami Resources Company, LLC. If the Asher lease is
terminated or if Nami Resources Company, LLC’s rights to production under wells
of which we have contract rights to receive proceeds are adversely affected, we
could lose our contract rights to receive such proceeds or it could be adversely
affected.




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








10.   
      Common Units and Net Income (Loss) per
Unit




In
April 2007, the sole member of VNG contributed all of the issued and
outstanding common units in VNG to VNR for six million common units representing
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 2.29 million
common units to certain private investors for $41.2 million. The proceeds of
this private equity offering were used to make a distribution to Majeed S. Nami,
VNR’s largest unitholder.  Mr. Nami used a portion of these funds to
capitalize Vinland and Vinland paid us $3.9 million to reduce outstanding
accounts receivable from Vinland. In October 2007, we successfully
completed our IPO of 5.25 million common units.




Basic
earnings per unit is computed in accordance with SFAS No. 128, “Earnings Per Share”
(“SFAS 128”) by dividing net earnings attributable to unitholders by the
weighted average number of units outstanding during the period. Diluted
earnings per unit is computed by adjusting the average number of units
outstanding for the dilutive effect, if any, of unit equivalents.  The
Company uses the treasury stock method to determine the dilutive effect. 
At December 31, 2008, the Company had two classes of units
outstanding:  (i) units representing limited liability company
interests (“common units”) listed on NYSE Arca under the symbol VNR and
(ii) Class B units, issued to officers and an employee as discussed in
Note 11.Unit-Based
Compensation.  The Class B units participate in distributions
and no forfeiture is expected; therefore, all Class B units were considered
in the computation of basic earnings per unit. The 175,000 options and phantom
units granted to officers under our long-term incentive plan had no dilutive
effect; therefore, they have been excluded from the computation of diluted
earnings per unit.




76
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In
accordance with SFAS 128, dual presentation of basic and diluted earnings
per unit has been presented in the consolidated statements of operations for the
years ended December 31, 2008 and 2007 for each class of units issued and
outstanding at that date: common units and Class B units.  Net income
(loss) per unit is allocated to the units and the Class B units on an equal
basis. No calculation was made for the Vanguard Predecessor
period.




11.   
Unit-Based Compensation




In
April 2007, the sole member reserved 460,000 restricted Class B units
in VNR for issuance to employees. Certain members of management were granted
365,000 restricted Class B units in VNR in April 2007, which vest two
years from the date of grant. In addition, another 55,000 restricted VNR
Class B units were issued in August 2007 to two other employees that
were hired in April and May, 2007, which will vest after three years. 
The remaining 40,000 restricted Class B units are available to be awarded
to new employees or members of our board of directors as they are
retained.  In October 2007 and February 2008, four board members were
granted 5,000 common units each which will vest after one year. Additionally, in
October 2007, two officers were granted options to purchase an aggregate of
175,000 units under our long-term incentive plan with an exercise price equal to
the initial public offering price of $19.00 which vested immediately upon being
granted, have a term of five years and had a fair value of $0.1 million on the
date of grant.





Furthermore,
on March 27, 2008, phantom units were granted to two officers in amounts equal
to 1% of our units outstanding at January 1, 2008 and the amount to be paid was
equal to the appreciation in value of the units, if any, from the date of the
grant until the determination date (December 31, 2008), plus cash distributions
paid on the units, less an 8% hurdle rate. As of December 31, 2008, there was no
appreciation in the value of these units; therefore, no liability or expense was
recognized. These common units, Class B units, options and phantom units were
granted as partial consideration for services to be performed under employment
contracts and thus are subject to accounting for these grants under SFAS 123(R),
Share-Based Payment.




The fair
value of restricted units issued is determined based on the fair market value of
VNR units on the date of the grant.  This value is amortized over the
vesting period as referenced above. A summary of the status of the non-vested
units as of December 31, 2008 is presented below:




Number of
                    Non-vested Units
                  
                  Weighted Average
                    Grant Date
                    Fair ValueNon-vested units at December 31, 2007
                  425,000
                  
                  $
                  18.14Granted
                  15,000
                  
                  16.79Non-vested
      units at December 31, 2008
                  440,000
                  
                  $
                  18.10




At
December 31, 2008, there was approximately $2.3 million of unrecognized
compensation cost related to non-vested restricted units.  The cost is
expected to be recognized over an average period of approximately 0.8 years. Our
consolidated statements of operations reflects non-cash compensation of $3.6
million and $2.1 million in the selling, general and administrative expenses
line item for the years ended December 31, 2008 and 2007,
respectively.


12.   
Subsequent Events




Our
reserve-based credit facility was amended in February 2009 to amend
covenants to allow the Company to repurchase up to $5.0 million of our own
units.





In
February 2009, we liquidated our 2012 oil swap and entered into new 2010 and
2011 natural gas swap and collar transactions. Specifically, an $8.04 and $7.85
fixed price NYMEX natural gas swap for January through September 2010 and April
through September 2011, respectively, was executed for 2,000 MMBtu/day. In
addition, a 2,000 MMBtu/day NYMEX natural gas collar with a floor price of $7.50
and a ceiling price of $9.00 for October 2010 through March 2011 and October
2011 through December 2011 was executed. These natural gas derivatives were set
at prices above the current market by using the proceeds of the liquidation of
the 2012 oil swap.







77
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Supplemental Selected Quarterly Financial Information
(Unaudited)




Financial
information by quarter is summarized below.




Quarters EndedMarch 31
                
                
                June 30
                
                
                September
      30
                
                
                December 31
                
                
                Total(in
      thousands, except per unit amounts)2008Natural gas and oil
      sales
                
                $
                14,002
                
                
                $
                20,852
                
                
                $
                20,839
                
                
                $
                13,157
                
                
                $
                68,850Gain (loss) on commodity cash
      flow hedges
                
                
                416
                
                
                
                155
                
                
                
                45
                
                
                
                (347
                )
                
                
                269Gain (loss) on other commodity
      derivative contracts
                
                
                (21,772
                )
                
                
                (58,045
                )
                
                
                63,364
                
                
                
                48,930
                
                
                
                32,477Total
      revenues
                
                
                (7,354
                )
                
                
                (37,038
                )
                
                
                84,248
                
                
                
                61,740
                
                
                
                101,596Impairment of natural gas and
      oil properties
                
                
                —
                
                
                
                —
                
                
                
                —
                
                
                
                58,887
                
                
                
                58,887Other costs and expenses (1)
                
                
                7,452
                
                
                
                8,696
                
                
                
                10,495
                
                
                
                11,059
                
                
                
                37,702Total costs and
      expenses
                
                
                7,452
                
                
                
                8,696
                
                
                
                10,495
                
                
                
                69,946
                
                
                
                96,589Net income
      (loss)
                
                $
                (15,932
                )
                
                $
                (47,020
                )
                
                $
                71,809
                
                
                $
                (12,608
                )
                
                $
                (3,751
                )Net income (loss) per
      unit:Common & Class B
      units – basic
                
                $
                (1.42
                )
                
                $
                (4.19
                )
                
                $
                5.90
                
                
                $
                (1.00
                )
                
                $
                (0.32
                )Common & Class B
      units – diluted
                
                $
                (1.42
                )
                
                $
                (4.19
                )
                
                $
                5.90
                
                
                $
                (1.00
                )
                
                $
                (0.32
                )2007Natural gas and oil
      sales
                
                $
                8,962
                
                
                $
                10,107
                
                
                $
                7,641
                
                
                $
                7,831
                
                
                $
                34,541Gain (loss) on commodity cash
      flow hedges
                
                
                (748
                )
                
                
                (918
                )
                
                
                940
                
                
                
                24
                
                
                
                (702
                )Total
      revenues
                
                
                8,214
                
                
                
                9,189
                
                
                
                8,581
                
                
                
                7,855
                
                
                
                33,839Total costs and expenses (1)
                
                
                5,128
                
                
                
                4,767
                
                
                
                5,026
                
                
                
                5,694
                
                
                
                20,615Net income
      (loss)
                
                $
                (1,626
                )
                
                $
                2,240
                
                
                $
                1,051
                
                
                $
                984
                
                
                $
                2,649Net income (loss) per
      unit:Common & Class B
      units – basic
                
                $
                (0.29
                )
                
                $
                0.38
                
                
                $
                0.18
                
                
                $
                0.10
                
                
                $
                0.39Common & Class B
      units – diluted
                
                $
                (0.2
      9
                )
                
                $
                0.38
                
                
                $
                0.18
                
                
                $
                0.10
                
                
                $
                0.39










(1)
            Includes
      lease operating expenses, depreciation, depletion, amortization and
      accretion, selling, general and administration expenses, bad debt expense
      and production and other taxes.










78
 Table of Contents








Supplemental Natural Gas and Oil Information
(Unaudited)




We are a
publicly-traded limited liability company focused on the acquisition and
development of mature, long-lived natural gas and oil properties in the United
States.




Capitalized
costs related to natural gas and oil producing activities and related
accumulated depletion, amortization and accretion were as follows at
December 31:




2008
                        
                        
                        2007Aggregate
      capitalized costs relating to natural gas and oil producing
      activities
                        
                        $
                        284,446,984
                        
                        
                        $
                        135,435,240Aggregate
      accumulated depletion, amortization and accretion
                        
                        
                        (102,178,304
                        )
                        
                        
                        (28,451,891
                        )Net
      capitalized costs
                        
                        $
                        182,268,680
                        
                        
                        $
                        106,983,349SFAS
      143 asset retirement obligations
                        
                        $
                        2,133,791
                        
                        
                        $
                        189,711




Costs
incurred in natural gas and oil producing activities, whether capitalized or
expensed, were as follows for the years ended December 31:




Vanguard
                                
                                
                                Vanguard
      Predecessor2008
                                
                                
                                2007
                                
                                
                                2006Property acquisition costs
                                
                                $
                                128,323,699
                                
                                
                                $
                                3,670,561
                                
                                
                                $
                                —Development
      costs
                                
                                
                                19,097,637
                                
                                
                                
                                12,859,838
                                
                                
                                
                                37,467,066Total
      cost incurred
                                
                                $
                                147,421,336
                                
                                
                                $
                                16,530,399
                                
                                
                                $
                                37,467,066




The table
above includes capitalized internal costs incurred in connection with the
development of natural gas and oil reserves of $3,880,000 in 2006. No internal
costs were capitalized in 2008 or 2007. Additionally, capitalized interest of
$58,960, $75,672 and $117,097 for the years ended December 31, 2008, 2007
and 2006, respectively, are included in the table above.




Net
quantities of proved developed and undeveloped reserves of natural gas and oil
and changes in these reserves at December 31, 2008, 2007 and 2006 are
presented below. Information in these tables is based on reserve reports
prepared by our independent petroleum engineers, Netherland, Sewell &
Associates, Inc. for 2008, 2007 and 2006.




Gas (in Mcf)
                
                
                Oil (in Bbls)Net
      proved reservesJanuary 1,
      2006
                
                
                107,690,281
                
                
                
                463,693Revisions
      of previous estimates
                
                
                (17,529,333
                )
                
                
                (106,630
                )Extensions,
      discoveries and other
                
                
                8,205,425
                
                
                
                18,623Production
                
                
                (4,181,708
                )
                
                
                (32,718
                )December 31,
      2006
                
                
                94,184,665
                
                
                
                342,968Revisions
      of previous estimates
                
                
                (31,943,375
                )
                
                
                798Extensions,
      discoveries and other
                
                
                4,544,443
                
                
                
                16,725Purchases
      of reserves in place
                
                
                2,387,113
                
                
                
                6,165Production
                
                
                (4,044,380
                )
                
                
                (30,629
                )December 31,
      2007
                
                
                65,128,466
                
                
                
                336,027Revisions
      of previous estimates
                
                
                (5,475,099
                )
                
                
                73,480Extensions,
      discoveries and other
                
                
                5,856,100
                
                
                
                25,017Purchases
      of reserves in place
                
                
                20,089,537
                
                
                
                4,374,410Production
                
                
                (4,361,907
                )
                
                
                (261,575
                )December 31,
      2008
                
                
                81,237,097
                
                
                
                4,547,359Proved
      developed reservesDecember 31,
      2006
                
                
                48,166,327
                
                
                
                249,329December 31,
      2007
                
                
                48,897,929
                
                
                
                233,507December 31,
      2008
                
                
                58,315,899
                
                
                
                3,766,394




Revisions
of previous estimates of reserves are a result of changes in natural gas and oil
prices, production costs, well




79
 Table of Contents




performance
and the reservoir engineer’s methodology. Changes in natural gas prices had a
significant impact on proved reserves in 2006. From December 31, 2005 to
December 31, 2006, the revisions of previous estimates for natural gas reduced
proved reserves by 17.5 Bcf largely due to natural gas prices decreasing from
$9.89 per MMbtu to $5.63 per MMbtu at the respective year ends. From December
31, 2006 to December 31, 2007, the revisions of previous estimates for natural
gas reduced proved reserves by 31.9 Bcf primarily due to the value of the 60%
interest in proved undeveloped properties which was conveyed to Vinland in the
Restructuring.





There are
numerous uncertainties inherent in estimating quantities of proved reserves,
projecting future rates of production and projecting the timing of development
expenditures, including many factors beyond our control. The reserve data
represents only estimates. Reservoir engineering is a subjective process of
estimating underground accumulations of natural gas and oil that cannot be
measured in an exact manner. The accuracy of any reserve estimate is a function
of the quality of available data and of engineering and geological
interpretations and judgment. All estimates of proved reserves are determined
according to the rules prescribed by the SEC. These rules indicate
that the standard of “reasonable certainty” be applied to proved reserve
estimates. This concept of reasonable certainty implies that as more technical
data becomes available, a positive, or upward, revision is more likely than a
negative, or downward, revision. Estimates are subject to revision based upon a
number of factors, including reservoir performance, prices, economic conditions
and government restrictions. In addition, results of drilling, testing and
production subsequent to the date of an estimate may justify revision of that
estimate. Reserve estimates are often different from the quantities of natural
gas and oil that are ultimately recovered. The meaningfulness of reserve
estimates is highly dependent on the accuracy of the assumptions on which they
were based. In general, the volume of production from natural gas and oil
properties we own declines as reserves are depleted. Except to the extent we
conduct successful development activities or acquire additional properties
containing proved reserves, or both, our proved reserves will decline as
reserves are produced. There have been no major discoveries or other events,
favorable or adverse, that may be considered to have caused a significant change
in the estimated proved reserves since December 31, 2008.




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




Vanguard
                                  
                                  
                                  Vanguard
      Predecessor2008
                                  
                                  
                                  2007
                                  
                                  
                                  2006Production revenues (1)
                                  
                                  $
                                  62,542,789
                                  
                                  
                                  $
                                  33,838,191
                                  
                                  
                                  $
                                  35,976,571Production
      costs (2)
                                  
                                  
                                  (15,799,836
                                  )
                                  
                                  
                                  (7,119,834
                                  )
                                  
                                  
                                  (6,670,542
                                  )Depreciation,
      depletion and amortization
                                  
                                  
                                  (14,812,305
                                  )
                                  
                                  
                                  (8,960,524
                                  )
                                  
                                  
                                  (8,511,390
                                  )Impairment
      of natural gas and oil properties
                                  
                                  
                                  (58,886,660
                                  )
                                  
                                  
                                  —
                                  
                                  
                                  
                                  —Results
      of operations from producing activities
                                  
                                  $
                                  (26,956,012
                                  )
                                  
                                  $
                                  17,757,833
                                  
                                  
                                  $
                                  20,794,639







(1)   Production
      revenues include gains and losses on commodity cash flow hedges in 2008
      and 2007 and realized losses on other commodity derivative contracts in
      2008 and 2006.


(2)   Production
      cost includes lease operating expenses and production related taxes,
      including ad valorem and severance
taxes.





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




Vanguard
                                
                                
                                Vanguard
      Predecessor2008
                                
                                
                                2007
                                
                                
                                2006Future cash inflows
                                
                                $
                                739,560
                                
                                
                                $
                                587,639
                                
                                
                                $
                                663,604Future
      production costs
                                
                                
                                (258,948
                                )
                                
                                
                                (173,485
                                )
                                
                                
                                (192,520
                                )Future
      development costs
                                
                                
                                (50,268
                                )
                                
                                
                                (36,842
                                )
                                
                                
                                (66,906
                                )Future
      net cash flows
                                
                                
                                430,344
                                
                                
                                
                                377,312
                                
                                
                                
                                404,17810%
      annual discount for estimated timing of cash flows
                                
                                
                                (240,271
                                )
                                
                                
                                (226,315
                                )
                                
                                
                                (255,357
                                )Standardized
      measure of discounted future net cash flows
                                
                                $
                                190,073
                                
                                
                                $
                                150,997
                                
                                
                                $
                                148,821




For the
December 31, 2008 calculations in the preceding table, estimated future
cash inflows from estimated future production of proved reserves were computed
using year-end prices of $5.71 per MMBtu for natural gas, adjusted by field for
energy content, and $41.00 per barrel of oil, adjusted for quality,
transportation fees and a regional price differential. We may receive amounts
different than the standardized measure of discounted cash flow for a number of
reasons, including price changes and the effects of our hedging
activities.




80
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The
following are the principal sources of change in our standardized measure of
discounted future net cash flows (in thousands):







Year Ended December 31, (1)Vanguard
                    
                    
                    Vanguard
      Predecessor2008
                    
                    
                    2007
                    
                    
                    2006Sales
      and transfers, net of production costs
                    
                    $
                    (53,050
                    )
                    
                    $
                    (26,718
                    )
                    
                    $
                    (29,306
                    )Net
      changes in prices and production costs
                    
                    
                    (20,385
                    )
                    
                    
                    52,625
                    
                    
                    
                    (231,630
                    )Extensions
      discoveries and improved recovery, less related costs
                    
                    
                    13,036
                    
                    
                    
                    10,791
                    
                    
                    
                    21,110Changes
      in estimated future development costs
                    
                    
                    (12,056
                    )
                    
                    
                    18,045
                    
                    
                    
                    (24,336
                    )Previously
      estimated development costs incurred during the period
                    
                    
                    19,956
                    
                    
                    
                    16,531
                    
                    
                    
                    37,467Revision
      of previous quantity estimates
                    
                    
                    (10,149
                    )
                    
                    
                    (75,071
                    )
                    
                    
                    (31,726
                    )Accretion
      of discount
                    
                    
                    15,100
                    
                    
                    
                    14,882
                    
                    
                    
                    40,043Purchases
      of reserves in place
                    
                    
                    82,454
                    
                    
                    
                    4,249
                    
                    
                    
                    —Change
      in production rates, timing and other
                    
                    
                    4,170
                    
                    
                    
                    (13,158
                    )
                    
                    
                    (33,230
                    )Net
      change
                    
                    $
                    39,076
                    
                    
                    $
                    2,176
                    
                    
                    $
                    (251,608
                    )






(1)This
      disclosure reflects changes in the standardized measure calculation
      excluding the effects of hedging
activities.







81
 Table of Contents










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




As
previously reported in our Current Report on Form 8-K dated September 2,
2008, on August 27, 2008, UHY LLP (“UHY”) advised us that, in light of the
Company’s employment of a member of the UHY audit engagement team, effective as
of September 8, 2008, UHY would no longer be able to serve as the Company’s
independent registered public accounting firm because it believed it would no
longer satisfy the independence requirements necessary to certify the financial
statements of the Company. As a result, UHY resigned as the Company’s
independent registered public accounting firm, effective as of August 27, 2008.
UHY expressed an unqualified opinion on the consolidated financial statements of
the Company for the year ended December 31, 2007 and the consolidated financial
statements of Vanguard Natural Gas, LLC (formerly Nami Holding Company, LLC) for
the year ended December 31, 2006. During the two most recent fiscal years and
interim period preceding UHY’s resignation, there were no (a) disagreements with
UHY or (b) any reportable events as defined under Item 304(a)(1)(v) of
Regulation S-K. Also, as previously reported in our Current Report on
Form 8-K dated October 14, 2008, our audit committee approved the
engagement terms of BDO Seidman, LLP (“BDO”) and authorized BDO to serve as our
independent registered public accountants for the fiscal year ending
December 31, 2008.


ITEM 9A.
            CONTROLS
      AND PROCEDURES




(a)
            Evaluation
      of Disclosure Controls and
Procedures




Our
management has established and maintains a system of disclosure controls and
procedures to provide reasonable assurances that information required to be
disclosed by us in reports that we file or submit under the Exchange Act is
recorded, processed, summarized and reported within the time periods specified
in the SEC’s rules and forms, and that such information is accumulated and
communicated to our management, including our Chief Executive Officer and Chief
Financial Officer, as appropriate to allow timely decisions regarding required
disclosure.
 
 As part
of the preparation of our financial statements for the quarters ended March 31,
2008 and June 30, 2008, we undertook a review of our accounting for natural gas
and oil and interest rate derivatives. We use derivative instruments as a means
of reducing financial exposure to fluctuating natural gas and oil prices and
interest rates. We included changes from period to period in the fair value of
derivatives classified as cash flow hedges as increases or decreases to
Accumulated Other Comprehensive Income (“AOCI”) as allowed by Statement of
Financial Accounting Standards No. 133, “Accounting for Derivative
Instruments and Hedging Activities” (“SFAS 133”). This hedge accounting
treatment is allowed for certain derivatives, including the types of derivatives
used by us to reduce exposure to changes in natural gas and oil prices
associated with the sale of natural gas and oil production and fluctuations in
interest rates. In order to qualify for hedge accounting treatment, specific
standards and documentation requirements must be met. We believed that we met
those requirements and that our hedge accounting treatment was permitted under
SFAS 133. However, in connection with preparing our quarterly report for third
quarter of 2008 and discussion with BDO, we determined that our commodity
derivative instruments did not qualify for hedge accounting treatment under SFAS
133 in 2008. Specifically, we determined that the formal hedge documentation
lacked specificity of the hedged cash flow and the quantitative subsequent
assessments for ineffectiveness were insufficient.  Therefore, the
cash flow designations failed to meet hedge documentation requirements for cash
flow hedge accounting treatment for commodity derivative contracts entered into
during periods subsequent to December 31, 2007; and, that accounting for
commodity derivative instruments entered into during periods subsequent to
December 31, 2007 as cash flow hedges was, therefore,
inappropriate.  In addition, the natural gas derivative swap contracts
entered into in 2007 were de-designated as cash flow hedges in the first quarter
of 2008 due to an overhedged position in natural gas which made them
ineffective.  Accordingly, we restated the consolidated financial
statements for the three months ended March 31, 2008 and June 30, 2008 as
reflected in our Form 10-Q’s to reflect the appropriate
changes.  Management has concluded, based on the circumstances
involving the restatement of the aforementioned financial statements that from
March 31, 2008 through September 30, 2008, a material weakness in internal
control over financial reporting existed with respect to the design of the
Company’s controls over the proper recording and disclosure of derivative
instruments in accordance with SFAS 133.


We
carried out an evaluation in accordance with Exchange Act Rules 13a-15
under the supervision and with the participation of management, including our
Chief Executive Officer and our Chief Financial Officer, of the effectiveness of
our disclosure controls and procedures as of the end of the period covered by
this report. Based on that evaluation, our Chief Executive Officer and Chief
Financial Officer concluded that, due to the aforementioned material weakness,
our disclosure controls and procedures were not effective through September 30,
2008.  The Company evaluated the necessary changes in control
procedures required to remediate this material weakness and elected to no longer
account for future derivative instruments as cash flow hedges under SFAS 133. As
such, the Company now recognizes changes in its derivatives’ fair value in
current earnings under gains (losses) on other commodity and interest rate
derivative contracts. Accordingly, the Company’s internal controls over
financial reporting were effective at the




82
 Table of Contents




reasonable
assurance level at December 31, 2008. See BDO Seidman, LLP’s report on our
internal control over financial reporting as of December 31, 2008 set forth
below in Part II, Item 9A (d) under Attestation Report.




(b)
            Management’s
      Annual Report on Internal Control Over Financial
  Reporting





Our
management is responsible for establishing and maintaining adequate internal
control over financial reporting, as defined by SEC rules adopted under the
Securities Exchange Act of 1934, as amended. Our internal control over financial
reporting is designed to provide reasonable assurance regarding the reliability
of financial reporting and the preparation of financial statements for external
purposes in accordance with generally accepted accounting principles. It
consists of policies and procedures that:





·
            Pertain
      to the maintenance of records that, in reasonable detail, accurately and
      fairly reflect the transactions and dispositions of our
      assets;





·
            Provide
      reasonable assurance that transactions are recorded as necessary to permit
      preparation of the financial statements in accordance with generally
      accepted accounting principles, and that our receipts and expenditures are
      being made only in accordance with authorizations of our management and
      directors; and





·
            Provide
      reasonable assurance regarding prevention or timely detection of
      unauthorized acquisition, use or disposition of our assets that could have
      a material effect on the financial
statements.





Under the
supervision and with the participation of management, including the Chief
Executive Officer (CEO) and Chief Financial Officer (CFO), we made an assessment
of the effectiveness of our internal control over financial reporting as of
December 31, 2008. In making this assessment, we used the criteria established
in Internal Control —
Integrated Frameworkissued by the Committee of Sponsoring Organizations
of the Treadway Commission (COSO). Based on our evaluation, we concluded that
our internal control over financial reporting was effective as of December 31,
2008. The effectiveness of our internal control over financial reporting as of
December 31, 2008 has been audited by BDO Seidman, LLP, an independent
registered public accounting firm, as stated in their report included
herein.


(c)
            Changes
      in Internal Control over Financial
Reporting




In
response to the material weakness noted in Item 9A (a) above during the fourth
quarter 2008, the Company elected to no longer account for future derivative
instruments as cash flow hedges under SFAS 133 and now recognizes changes in its
derivatives’ fair value in current earnings under gains (losses) on other
commodity and interest rate derivative contracts. There were no other changes in
our internal control over financial reporting during this quarter that
materially affected, or are reasonably likely to materially affect, our internal
control over financial reporting.





(d)
            Attestation
      Report





Report
of Independent Registered Public Accounting Firm


on
Internal Control over Financial Reporting




Board of
Directors and Shareholders


Vanguard
Natural Resources, LLC


Houston,
Texas




We have
audited Vanguard Natural Resources, LLC’s internal control over financial
reporting as of December 31, 2008, based on criteria established in Internal Control – Integrated
Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission (the COSO criteria). Vanguard Natural Resources, LLC’s
management is responsible for maintaining effective internal control over
financial reporting and for its assessment of the effectiveness of internal
control over financial reporting, included in the accompanying “Item 9A,
Management’s Report on Internal Control Over Financial Reporting.” Our
responsibility is to express an opinion on the company’s internal control over
financial reporting based on our audit.




We
conducted our audit in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether effective
internal control over financial reporting was maintained in all material
respects. Our audit included obtaining an understanding of internal control over
financial reporting, assessing the risk that a material weakness exists, and
testing and evaluating the design and operating effectiveness of internal
control based on the assessed risk. Our audit also included performing such
other procedures as we considered necessary in the circumstances. We believe
that our audit provides a reasonable basis for our opinion.




83
 Table of Contents


A
company’s internal control over financial reporting is a process designed to
provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance
with generally accepted accounting principles. A company’s internal control over
financial reporting includes those policies and procedures that (1) pertain to
the maintenance of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the company; (2)
provide reasonable assurance that transactions are recorded as necessary to
permit preparation of financial statements in accordance with generally accepted
accounting principles, and that receipts and expenditures of the company are
being made only in accordance with authorizations of management and directors of
the company; and (3) provide reasonable assurance regarding prevention or timely
detection of unauthorized acquisition, use, or disposition of the company’s
assets that could have a material effect on the financial
statements.




Because
of its inherent limitations, internal control over financial reporting may not
prevent or detect misstatements. Also, projections of any evaluation of
effectiveness to future periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree of compliance
with the policies or procedures may deteriorate.




In our
opinion, Vanguard Natural Resources, LLC maintained, in all material respects,
effective internal control over financial reporting as of December 31, 2008,
based on the COSO criteria.






We also
have audited, in accordance with the standards of the Public Company
Accounting Oversight Board (United States), the consolidated balance sheet of
Vanguard Natural Resources LLC as of December 31, 2008 and the related
consolidated statements of operations, comprehensive income (loss), members’
equity, and cash flows for the year ended December 31, 2008 and our report dated
March 10, 2009 expressed an unqualified opinion thereon.




/s/ BDO
Seidman, LLP






Houston,
Texas


March 10,
2009





ITEM 9B.
            OTHER
      INFORMATION




None.




PART III




ITEM 10.
            DIRECTORS,
      EXECUTIVE OFFICERS AND CORPORATE
GOVERNANCE




Item 10
will be incorporated by reference pursuant to Regulation 14A under the
Securities Exchange Act of 1934.  The Registrant expects to file a
definitive proxy statement with the Securities and Exchange Commission within
120 days after the close of the year ended December 31, 2008.




ITEM 11.
            EXECUTIVE
      COMPENSATION




Item 11
will be incorporated by reference pursuant to Regulation 14A under the
Securities Exchange Act of 1934.  The Registrant expects to file a
definitive proxy statement with the Securities and Exchange Commission within
120 days after the close of the year ended December 31, 2008.




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




Item 12
will be incorporated by reference pursuant to Regulation 14A under the
Securities Exchange Act of 1934.  The Registrant expects to file a
definitive proxy statement with the Securities and Exchange Commission within
120 days after the close of the year ended December 31, 2008.




ITEM 13.
            CERTAIN
      RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR
      INDEPENDENCE




Item 13
will be incorporated by reference pursuant to Regulation 14A under the
Securities Exchange Act of 1934.  The Registrant expects to file a
definitive proxy statement with the Securities and Exchange Commission within
120 days after the close of the year ended December 31, 2008.




84
 Table of Contents




ITEM 14.
            PRINCIPAL
      ACCOUNTANT FEES AND SERVICES




Item 14
will be incorporated by reference pursuant to Regulation 14A under the
Securities Exchange Act of 1934.  The Registrant expects to file a
definitive proxy statement with the Securities and Exchange Commission within
120 days after the close of the year ended December 31, 2008.







85
 Table of Contents








PART IV




ITEM 15.   EXHIBITS AND FINANCIAL STATEMENT
SCHEDULES




(a)  The
following documents are filed as a part of this report:




Financial
      statements





The
following consolidated financial statements are included in Part II,
Item 8 of this report:




PageReports of Independent Registered Public Accounting
      Firms
            56Consolidated Statements of
    Operations
            59Consolidated Balance Sheets
            60Consolidated Statements of Members’
      Equity
            61Consolidated Statements of Cash Flows
            62Consolidated Statements of Other Comprehensive Income
      (Loss)
            63Notes to Consolidated Financial
    Statements
            64




(b)    
      Exhibits




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




Exhibit No.
            
            Exhibit Title
            
            Incorporated by Reference to the
      Following3.1
            
            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
            
            Vanguard
      Natural Resources, LLC Long-Term Incentive Plan
            
            Form
      8-K, filed October 24, 2007 (File No. 001-33756)10.2
            
            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)10.3
            
            Vanguard
      Natural Resources, LLC Class B Unit Plan
            
            Form
      8-K, filed October 24, 2007 (File No. 001-33756)10.4
            
            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)10.5
            
            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)10.6
            
            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)10.7
            
            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)10.8
            
            Gathering
      and Compression Agreement, effective January 5, 2007, by and between
      Vinland Energy Gathering, LLC, Vinland Energy Eastern, LLC, Vanguard
      Natural Gas, LLC and Trust Energy Company
            
            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 and Nami Resources Company,
      L.L.C.
            
            Form
      S-1/A, filed April 25, 2007 (File No. 333-142363)10.10
            
            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)10.11
            
            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)10.12
            
            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)   86
 Table of Contents
   10.13
              
              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)10.14
              
              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)10.15
              
              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)10.16
              
              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)10.17
              
              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)10.18
              
              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)10.19
              
              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)10.20
              
              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)10.21
              
              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)10.22
              
              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)10.23
              
              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)10.24
              
              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)10.25
              
              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)10.26
              
              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)10.27
              
              Director
      Compensation Agreement
              
              Form
      S-1/A, filed September 18, 2007 (File No. 333-142363)10.28
              
              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)10.29
              
              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)10.30
              
              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
              
              Previously
      filed with our Form 10-K on March 31, 200810.31
              
              Purchase
      and Sale Agreement, dated July 18, 2008, among Vanguard Permian, LLC and
      Segundo Navarro Drilling, Ltd.
              
              Form
      8-K, filed July 21, 2008 (File No. 001-33756)10.32
              
              Form
      of Indemnity Agreement dated August 7, 2008
              
              Previously
      filed with our Quarterly report on Form 10-Q on August 13,
      200810.33
              
              Second
      Amendment to First Amended and Restated Credit Agreement, dated October
      22, 2008, by and between Vanguard Natural Gas, LLC, Compass Bank, as
      lender, and Citibank, N.A., as administrative agent
              
              Previously
      filed with our Quarterly report on Form 10-Q on November 14,
      200810.34
              
              First
      Amendment to First Amended and Restated Credit Agreement, dated May 15,
      2008, by and between Vanguard Natural Gas, LLC, lenders party thereto, and
      Citibank, N.A., as administrative agent
              
              Filed
      herewith10.35
              
              Third
      Amendment to First Amended and Restated Credit Agreement, dated February
      18, 2009, by and between Vanguard Natural Gas, LLC, lenders party thereto,
      and Citibank, N.A., as administrative agent
              
              Filed
      herewith16.1
              
              Letter
      re change in certifying accountant
              
              Form
      8-K, filed on September 2, 2008 (File No. 001-33756)21.1
              
              List
      of subsidiaries of Vanguard Natural Resources, LLC
              
              Filed
      herewith31.1
              
              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
      herewith31.2
              
              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
      herewith32.1
              
              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
  87
 Table of Contents
  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











88
 Table of Contents




SIGNATURES
  Pursuant
to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, Vanguard Natural Resources, LLC has duly caused this report to be
signed on its behalf by the undersigned, thereunto duly authorized on the
11th
day of March, 2009.
  VANGUARD
      NATURAL RESOURCES, LLCBy:
                /s/ Scott
      W. SmithScott
      W. SmithPresident
      and Chief Executive Officer
   KNOW ALL
MEN BY THESE PRESENTS, that each person whose signature appears below
constitutes and appoints Scott W. Smith and Richard A. Robert, and each of them
severally, his true and lawful attorney or attorneys-in-fact and agents, with
full power to act with or without the others and with full power of substitution
and resubstitution, to execute in his name, place and stead, in any and all
capacities, any or all amendments to this Annual Report on Form 10-K, with
all exhibits thereto, and other documents in connection therewith, with the
Securities and Exchange Commission, granting unto said attorneys-in-fact and
agents and each of them, full power and authority to do and perform in the name
of on behalf of the undersigned, in any and all capacities, each and every act
and thing necessary or desirable to be done in and about the premises, to all
intents and purposes and as fully as they might or could do in person, hereby
ratifying, approving and confirming all that said attorneys-in-fact and agents
or their substitutes may lawfully do or cause to be done by virtue
hereof.
  Pursuant
to the requirements of the Securities Exchange Act of 1934, this report has been
signed below by the following persons on behalf of the registrant and in the
capacities and on the dates indicated.
   March 11,
      2009
              /s/
      Scott W. SmithScott
      W. SmithPresident,
      Chief Executive Officer and Director(Principal
      Executive Officer)March 11,
      2009
              /s/
      Richard A. RobertRichard
      A. RobertExecutive
      Vice President and ChiefFinancial
      Officer (Principal Financial Officer)March 11,
      2009
              /s/
      W. Richard AndersonW.
      Richard AndersonDirectorMarch 11,
      2009
              /s/
      Bruce W. McCulloughBruce
      W. McCulloughDirectorMarch 11,
      2009
              /s/
      John R. McGoldrickJohn
      R. McGoldrickDirectorMarch 11,
      2009
              /s/
      Loren SingletaryLoren
      SingletaryDirectorMarch 11,
      2009
              /s/
      Lasse WageneLasse
      WageneDirector








89
 Table of Contents




Vanguard
Natural Resources, LLC
 EXHIBIT
INDEX
  Each
exhibit identified below is filed as a part of this Report.
   Exhibit
      No.
                
                Exhibit
      Title
                
                Incorporated
      by Reference to the Following3.1
                
                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
                
                Vanguard
      Natural Resources, LLC Long-Term Incentive Plan
                
                Form
      8-K, filed October 24, 2007 (File No. 001-33756)10.2
                
                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)10.3
                
                Vanguard
      Natural Resources, LLC Class B Unit Plan
                
                Form
      8-K, filed October 24, 2007 (File No. 001-33756)10.4
                
                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)10.5
                
                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)10.6
                
                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)10.7
                
                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)10.8
                
                Gathering
      and Compression Agreement, effective January 5, 2007, by and between
      Vinland Energy Gathering, LLC, Vinland Energy Eastern, LLC, Vanguard
      Natural Gas, LLC and Trust Energy Company
                
                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 and Nami Resources Company,
      L.L.C.
                
                Form
      S-1/A, filed April 25, 2007 (File No. 333-142363)10.10
                
                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)10.11
                
                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)10.12
                
                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)10.13
                
                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)10.14
                
                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)10.15
                
                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)10.16
                
                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)10.17
                
                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)10.18
                
                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)10.19
                
                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)10.20
                
                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)10.21
                
                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)10.22
                
                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)10.23
                
                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)10.24
                
                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)10.25
                
                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)10.26
                
                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)10.27
                
                Director
      Compensation Agreement
                
                Form
      S-1/A, filed September 18, 2007 (File No. 333-142363)10.28
                
                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)10.29
                
                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)10.30
                
                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
                
                Previously
      filed with our Form 10-K on March 31, 200810.31
                
                Purchase
      and Sale Agreement, dated July 18, 2008, among Vanguard Permian, LLC and
      Segundo Navarro Drilling, Ltd.
                
                Form
      8-K, filed July 21, 2008 (File No. 001-33756)10.32
                
                Form
      of Indemnity Agreement dated August 7, 2008
                
                Previously
      filed with our Quarterly report on Form 10-Q on August 13,
      200810.33
                
                Second
      Amendment to First Amended and Restated Credit Agreement, dated October
      22, 2008, by and between Vanguard Natural Gas, LLC, Compass Bank, as
      lender, and Citibank, N.A., as administrative agent
                
                Previously
      filed with our Quarterly report on Form 10-Q on November 14,
      200810.34
                
                First
      Amendment to First Amended and Restated Credit Agreement, dated May 15,
      2008, by and between Vanguard Natural Gas, LLC, lenders party thereto, and
      Citibank, N.A., as administrative agent
                
                Filed
      herewith10.35
                
                Third
      Amendment to First Amended and Restated Credit Agreement, dated February
      18, 2009, by and between Vanguard Natural Gas, LLC, lenders party thereto,
      and Citibank, N.A., as administrative agent
                
                Filed
      herewith16.1
                
                Letter
      re change in certifying accountant
                
                Form
      8-K, filed on September 2, 2008 (File No. 001-33756)21.1
                
                List
      of subsidiaries of Vanguard Natural Resources, LLC
                
                Filed
      herewith31.1
                
                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
      herewith31.2
                
                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
      herewith32.1
                
                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
      herewith32.2
                
                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









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