Attached files

file filename
EX-21.1 - LIST OF SUBSIDIARIES OF VANGUARD NATURAL RESOURCES, LLC - Vanguard Natural Resources, Inc.exhibit21-1.htm
EX-31.2 - CERTIFICATION OF CHIEF FINANCIAL OFFICER PURSUANT TO RULE 13A ? 14 OF THE SECURITIES AND EXCHANGE ACT OF 1934, AS ADOPTED PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002 - Vanguard Natural Resources, Inc.exhibit31-2.htm
EX-23.2 - CONSENT OF DEGOLYER AND MACNAUGHTON, INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS - Vanguard Natural Resources, Inc.exhibit23-2.htm
EX-32.1 - CERTIFICATION OF CHIEF EXECUTIVE OFFICER PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 - Vanguard Natural Resources, Inc.exhibit32-1.htm
EX-23.1 - CONSENT OF BDO USA, LLP, INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM - Vanguard Natural Resources, Inc.exhibit23-1.htm
EX-31.1 - CERTIFICATION OF CHIEF EXECUTIVE OFFICER PURSUANT TO RULE 13A ? 14 OF THE SECURITIES AND EXCHANGE ACT OF 1934, AS ADOPTED PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002 - Vanguard Natural Resources, Inc.exhibit31-1.htm
EX-99.1 - REPORT OF DEGOLYER AND MACNAUGHTON, INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS - Vanguard Natural Resources, Inc.exhibit99-1.htm
EX-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 - Vanguard Natural Resources, Inc.exhibit32-2.htm



UNTED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
FORM 10-K
     
(Mark One)
 
 
x
 
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
     
   
For the fiscal year ended December 31, 2010
 
   
Or
     
o
 
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
     
   
For 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.)
     
5847 San Felipe, Suite 3000
 Houston, Texas
 
77057
(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 Registered
     
Common Units
 
New York Stock Exchange
 
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.
   
Yes o
 
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.
   
Yes o
 
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.
   
Yes x
 
No o
 
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
   
Yes o
 
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 the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
     
Large accelerated filero
 
Accelerated filerx
Non-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, 2010 was approximately $397,020,016 based upon the New York Stock Exchange composite transaction closing price.
 
As of March 1, 2011 29,770,627 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 2011 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, 2010 (“this Annual Report”).
 
 

 

 
Vanguard Natural Resources, LLC
 
TABLE OF CONTENTS
 
 
Caption
 
Page
 
   
     
   
     
   
     
   
 
 
 

 

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, natural gas, natural gas liquids, product price, oil, natural gas and natural gas liquids 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 oil, natural gas and natural gas liquids prices;

 
·                  the potential for additional impairment due to future declines in oil, natural gas and natural gas liquids prices;

 
·                  uncertainties about the estimated quantities of oil, natural gas and natural gas liquids reserves, including uncertainties about the effects of the Securities and Exchange Commission’s (“SEC”) new rules governing reserve reporting;               
 
 
 
·                  the conditions of the capital markets, interest rates, availability of credit facilities to support business requirements, liquidity and general economic conditions;
 
 
 
·                  the discovery, estimation, development and replacement of oil, natural gas and natural gas liquids reserves;
 
 
 
·                  our business and financial strategy;
 
 
 
·                  our drilling locations;
 
 
 
·                  technology;
 
 
 
·                  our cash flow, liquidity and financial position;
 
 
 
·                  the timing and amount of our future production of oil, natural gas and natural gas liquids;
 
 
 
·                  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;

 
·                  the ability of Encore Energy Partners LP to make distributions to its unitholders and general partner;
 
 
 
·                  our prospect development and property acquisitions;
 
 
 
·                  the marketing of oil, natural gas and natural gas liquids;
 
 
 
·                  competition in the oil, natural gas and natural gas liquids industry;
 
 
 
·                  the impact of weather and the occurrence of natural disasters such as fires, floods, hurricanes, earthquakes and other catastrophic events and natural disasters;
 
 
 
·                  governmental regulation of the oil and natural gas industry;
 
 
 
·                  environmental regulations;

 
·                  the effect of legislation, regulatory initiatives and litigation related to climate change;
 
 
 
·                  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.
 
 

 
 
 
Below is a list of terms that are common to our industry and used throughout this document:
 
/day
 
= per day
 
Mcf
 
= thousand cubic feet
             
Bbls
 
= barrels
 
Mcfe
 
= thousand cubic feet of natural gas equivalents
             
Bcf
 
= billion cubic feet
 
MGal
 
= thousand gallons
             
Bcfe
 
= billion cubic feet equivalents
 
MMBbls
 
= million barrels
             
BOE
 
= barrel of oil equivalent
 
MMBOE
 
= million barrels of oil equivalent
             
Btu
 
= British thermal unit
 
MMBtu
 
= million British thermal units
             
Gal
 
= gallons
 
MMcf
 
= million cubic feet
             
MBbls
 
= thousand barrels
 
MMcfe
 
= million cubic feet of natural gas equivalents
             
MBOE
 
= thousand barrels of oil equivalent
 
 NGLs
 
 = natural gas liquids
 
When we refer to oil, natural gas and natural gas liquids in “equivalents,” we are doing so to compare quantities of oil and natural gas liquids 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 42 gallons is equal to one Bbl of oil or one Bbl of natural gas liquids and one Bbl of oil or one Bbl of natural gas liquids 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 (“VNG”), Trust Energy Company, LLC (“TEC”), VNR Holdings, LLC (“VNRH”), Ariana Energy, LLC (“Ariana Energy”), Vanguard Permian, LLC (“Vanguard Permian”), VNR Finance Corp. (“VNRF”), Encore Energy Partners GP LLC (“ENP GP”), Encore Energy Partners LP (“ENP”), Encore Energy Partners Operating LLC (“OLLC”), Encore Energy Partners Finance Corporation (“ENPF”), Encore Clear Fork Pipeline LLC (“ECFP”) and (2) “Vanguard Predecessor,” “Predecessor,” “our operating subsidiary” or “VNG” are to Vanguard Natural Gas, LLC.
 
 

 
 
 
 
Overview
 
 
We are a publicly traded limited liability company focused on the acquisition and development of mature, long-lived oil and natural gas 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 oil and natural gas properties. We own a 100% controlling interest, through certain of our subsidiaries, in properties and oil and natural gas reserves located in four operating areas:

 
·
the Permian Basin in west Texas and New Mexico;

 
·
south Texas;

 
·
the southern portion of the Appalachian Basin, primarily in southeast Kentucky and northeast Tennessee; and

 
·
Mississippi.

In addition, we own an approximate 46.7% aggregate controlling interest through our subsidiary, Encore Energy Partners LP (“ENP”), in properties and oil and natural gas reserves located in four operating areas:

 
·
the Permian Basin in west Texas and New Mexico;

 
·
the Big Horn Basin in Wyoming and Montana;

 
·
the Williston Basin in North Dakota and Montana; and

 
·
the Arkoma Basin in Arkansas and Oklahoma.
 
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 New York Stock Exchange under the symbol “VNR.”

 
Recent Developments

On December 31, 2010, we completed an acquisition pursuant to a Purchase Agreement with Denbury Resources Inc. (“Denbury”), Encore Partners GP Holdings LLC, Encore Partners LP Holdings LLC and Encore Operating, L.P. (collectively, the “Encore Selling Parties” and, together with Denbury, the “Selling Parties”) to acquire (the “Encore Acquisition” or “Encore”) all of the member interest in ENP GP, the general partner of ENP and 20,924,055 common units representing limited partnership interests in ENP (the “ENP Units”), representing an approximate 46.7% aggregate controlling interest in ENP. As consideration for the purchase, we paid $300.0 million in cash and paid $80.0 million in stock by issuing 3,137,255 VNR common units, at an agreed upon price of $25.50 per unit, valued at the closing price of $29.65 at December 31, 2010.

In connection with the closing of the Encore Acquisition, VNG entered into a Second Amended and Restated Administrative Services Agreement, dated December 31, 2010, with ENP, ENP GP, Encore Operating, L.P. (“Encore Operating”), OLLC and Denbury (the “Services Agreement”).  The Services Agreement was amended solely to add VNG as a party and provide for VNG to assume the rights and obligations of Encore Operating and Denbury under the previous administrative services agreement going forward.
 
Pursuant to the Services Agreement, VNG will provide certain general and administrative services to ENP, ENP GP and the OLLC (collectively, the “ENP Group”) in exchange for a quarterly fee of $2.06 per barrel of oil equivalent of the ENP Group’s total net oil and gas production for the most recently-completed quarter, which fee is paid by ENP (the “Administrative Fee”).  The Administrative Fee is subject to certain index-related adjustments on an annual basis.  ENP also is obligated to reimburse VNG for all third-party expenses it incurs on behalf of the ENP Group.  These terms are identical to the terms under which Denbury and Encore Operating provided administrative services to the ENP Group prior to the second amendment and restatement of the Services Agreement.
 
 
1

 
As the acquisition was completed on December 31, 2010, no results of operations were included in the consolidated statement of operations for the year ended December 31, 2010. The fair value of the assets and liabilities we acquired on December 31, 2010 in the Encore Acquisition and cash flows associated with the transaction were included in the consolidated balance sheet as of December 31, 2010 and the statement of cash flows for the year ended December 31, 2010, respectively. As of December 31, 2010, based on a reserve report prepared by our independent reserve engineers, the properties owned by ENP have estimated reserves of 41.1 MMBOE (21.9 MMBOE attributable to the non-controlling interest), 67% of which is oil and 87% of which is proved developed producing.
 
 
Organizational Structure

The following diagram depicts our organizational structure as of March 8, 2011:
 

 
 
Formation and Acquisitions of Oil and Natural Gas Properties
 
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, was our founding unitholder. As part of the separation, we retained all of our Predecessor’s proved producing wells and associated reserves located in Appalachia. 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 oil and natural gas 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. We refer to these events as the “Restructuring.” 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. As of December 31, 2010, based on a reserve report prepared by our independent reserve engineers, the Appalachia properties have estimated reserves of 7.6 MMBOE, 95% of which is gas and 68% of which is proved developed producing.
 
2

 
On December 21, 2007, we entered in to a Purchase and Sale Agreement with the Apache Corporation for the purchase of certain oil and natural gas properties located in ten separate fields in the Permian Basin of west Texas and southeastern New Mexico, 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. The post-closing adjustments reduced the final purchase price to $71.5 million which 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), of which we operate 56 gross wells (54 net wells). With respect to operations, we established two district offices, one in Lovington, New Mexico and the other in Christoval, Texas to manage these assets. Our operating focus has been on maximizing existing production and looking for complementary acquisitions that we can add to this operating platform. As of December 31, 2010, based on a reserve report prepared by our independent reserve engineers, these acquired properties have estimated proved reserves of 3.4 MMBOE, 90% of which is oil and 89% of which is proved developed producing.

On July 18, 2008, we entered into a Purchase and Sale Agreement with Segundo Navarro Drilling, Ltd. (“Segundo”), a wholly-owned subsidiary of the Lewis Energy Group (“Lewis”), for the acquisition of certain oil and natural gas properties located in the Dos Hermanos Field in Webb County, Texas, referred to as the “Dos Hermanos 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. This acquisition was funded with $30.0 million of borrowings under our reserve-based credit facility and through the issuance of 1,350,873 VNR common units. In this purchase, we acquired an average of a 98% working interest in 90 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 operates all the properties and is contractually obligated to drill seven wells each year from 2011 through 2013 unless mutually agreed not to do so. 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. As of December 31, 2010, based on a reserve report prepared by our independent reserve engineers, these acquired properties have estimated proved reserves of 2.8 MMBOE, 99% of which is natural gas and natural gas liquids and 60% of which is proved developed producing.

On July 17, 2009, we entered into a Purchase and Sale Agreement with Segundo to acquire certain oil and natural gas properties located in the Sun TSH Field in La Salle County, Texas for $52.3 million, referred to as the “Sun TSH acquisition.” The acquisition had a July 1, 2009 effective date and was completed on August 17, 2009 for an adjusted purchase price of $50.5 million. An affiliate of Lewis operates all of the wells acquired in this transaction. This acquisition was funded with borrowings under our reserve-based credit facility and proceeds from the Company’s public equity offering of 3.9 million common units completed on August 17, 2009. At closing, we assumed natural gas puts and swaps based on NYMEX pricing for approximately 61% of the estimated gas production from then-existing producing wells in the acquired properties for the period beginning August of 2009 through December of 2010, which had a fair value of $4.1 million on the closing date. In addition, concurrent with the execution of the Purchase and Sale Agreement, we entered into a collar for certain volumes in 2010 and a series of collars for a substantial portion of the expected gas production for 2011 at prices above the then-current market price with a total cost to the Company of $3.1 million, which was financed through deferred premiums. As of December 31, 2010, based on a reserve report prepared by our independent reserve engineers, these acquired properties have estimated proved reserves of 6.1 MMBOE, 98% of which is natural gas and natural gas liquids and 60% of which is proved developed producing.

On November 27, 2009, we entered into a Purchase and Sale Agreement, Lease Amendment and Lease Royalty Conveyance Agreement and a Conveyance Agreement to acquire certain producing oil and natural gas properties located in Ward County, Texas in the Permian Basin from private sellers, referred to as the “Ward County acquisition.” This transaction had an effective date of October 1, 2009 and was closed on December 2, 2009 for $55.0 million. This acquisition was initially funded with borrowings under our reserve-based credit facility with borrowings being reduced by $40.3 million shortly thereafter with the proceeds from a 2.3 million common unit offering. We operate all but one of the ten wells acquired in this transaction. As of December 31, 2010, based on a reserve report prepared by our independent reserve engineers, these acquired properties have estimated proved reserves of 3.7 MMBOE, 74% of which is oil and 59% of which is proved developed producing.

On April 30, 2010, we entered into a definitive agreement with a private seller for the acquisition of certain oil and natural gas properties located in Mississippi, Texas and New Mexico. We refer to this acquisition as the “Parker Creek acquisition.” The purchase price for said assets was $113.1 million with an effective date of May 1, 2010. We completed this acquisition on May 20, 2010. The adjusted purchase price of $114.3 million considered final purchase price adjustments of approximately $1.2 million. The purchase price was funded from the approximate $71.5 million in net proceeds from our May 2010 equity offering and with borrowings under the Company’s existing reserve-based credit facility. As of December 31, 2010, based on a reserve report prepared by our independent reserve engineers, these acquired properties had estimated proved reserves of 4.3 MMBOE, 97% of which is oil and 37% of which is proved developed producing.
 
3

 
 
 
Proved Reserves

Based on reserve reports prepared by our independent reserve engineers, DeGolyer and MacNaughton, or “D&M,” our total estimated proved reserves at December 31, 2010 were 69.3 MMBOE, of which approximately 55% were oil reserves and 80% were classified as proved developed. At December 31, 2010, we owned working interests in 4,895 gross (2,270 net) productive wells. Our estimated proved reserves and productive wells at December 31, 2010 include those proved reserves and productive wells that we acquired in connection with the Encore Acquisition and are subject to a 53.3% non-controlling interest in ENP. Our average net production for the year ended December 31, 2010 was 4,721 BOE per day. Our average net production did not include any production from properties acquired in connection with the Encore Acquisition. We also have a 40% working interest in approximately 109,291 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 9%, or 2.4 MMBOE, of our estimated proved reserves as of December 31, 2010 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. 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 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 and the Permian Basin, VNR owns working interests ranging from 30-100% in approximately 15,890 undeveloped acres surrounding our existing wells. Additionally, ENP owns working interests ranging from 8-77% in approximately 15,372 undeveloped acres surrounding their existing wells.

Our average proved reserves-to-production ratio, or average reserve life, is approximately 14 years based on our total proved reserves as of December 31, 2010 including proved reserves associated with properties acquired in the Encore Acquisition and the combined production of VNR and ENP for 2010. Our proved reserves associated with properties acquired in the Encore Acquisition and the production of ENP are subject to a 53.3% non-controlling interest in ENP. As of December 31, 2010, we have identified 460 proved undeveloped drilling locations and over 205 other drilling locations on our leasehold acreage.

 
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 oil and natural gas assets with a focus on maintaining cash flow levels;

 
·
Replace reserves either through the development of our extensive inventory of proved undeveloped locations or make accretive acquisitions of oil and natural gas 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 oil and natural gas prices.

 
Properties

As of December 31, 2010, we own a 100% controlling interests, through certain of our subsidiaries, in oil and gas properties located in the Permian Basin, South Texas, Appalachian Basin, and Mississippi. We own an approximate 46.7% aggregate controlling interest in ENP’s properties located in the Permian Basin, Big Horn Basin, Williston Basin and the Arkoma Basin. The following table presents the production for the year ended December 31, 2010 and the estimated proved reserves for each operating area:
 
4

 
 
           
 
 
    Operator  
2010 Net
 
Net Estimated
 
       
 
 
 
 
VNR Properties:              
  Permian Basin   Vanguard Permian, LLC  
498.2
 
7,345
 
  South Texas:              
        Sun TSH Field   Lewis Petroleum  
302.5
 
6,094
 
Other
 
Lewis Petroleum
 
170.0
 
2,838
 
  Appalachian Basin
 
Vinland Energy Operations, LLC
 
602.6
 
7,599
 
  Mississippi
 
Roundtree and Associates
 
149.7
 
4,336
 
ENP Properties:
             
  Permian Basin
 
OLLC
 
 
16,367
(2)
  Big Horn Basin
 
OLLC
 
 
18,334
(2)
  Williston Basin
 
OLLC
 
 
4,957
(2)
  Arkoma Basin
 
OLLC
 
 
1,416
(2)
 
(1)
 
No production results are included for properties acquired on December 31, 2010 related to the Encore Acquisition.
(2)
 
Includes the non-controlling interest of approximately 53.3% as of December 31, 2010.

Following is a description of our properties by operating areas:

Permian Basin Properties

The Permian Basin is one of the largest and most prolific oil and natural gas producing basins in the United States. The Permian Basin extends over 100,000 square miles in West Texas and southeast New Mexico and has produced over 24 billion Bbls of oil since its discovery in 1921. The Permian Basin is characterized by oil and natural gas fields with long production histories and multiple producing formations.

During 2010, our Permian Basin operations produced approximately 498.2 MBOE. These properties accounted for approximately 23,712 MBOE or 34% of our total estimated proved reserves at year end, of which 19,562 MBOE were proved developed and 4,150 MBOE were proved undeveloped. This includes 16,367 MBOE acquired in the Encore Acquisition of which 78% were proved developed. As of December 31, 2010, our Permian Basin properties consisted of 79,910 gross (54,415 net) acres.

South Texas Properties

Most of our South Texas properties are operated by Lewis Petroleum and are located in two fields, Gold River North Field and Sun TSH Field, located in Webb and LaSalle Counties, Texas. Vanguard’s working interest ranges from 45% to 100%. Most of the production is high BTU gas that is produced from the Olmos and Escondido sand formations from a depth ranging from 4,700 feet to 7,800 feet.

During 2010, the South Texas properties produced approximately 472.5 MBOE, of which 42% was oil, condensate and NGLs. These properties accounted for approximately 8,932 MBOE or 13% of our total estimated proved reserves at year end, of which 5,667 MBOE were proved developed and 3,265 MBOE were proved undeveloped. As of December 31, 2010, our South Texas properties consisted of 21,020 gross (14,267 net) acres.

Appalachian Basin Properties

Most of our Appalachia properties are operated by Vinland and are located in southeastern Kentucky and northeastern Tennessee. The working interest ranges from 40% to 100% for most of Vanguard’s approximate 1,025 wells. Most of the production is high BTU gas that produces primarily from the Maxon, Big Lime and Devonian Shale from a depth ranging from approximately 1,500 feet to 4,500 feet.

During 2010, the Appalachia properties produced approximately 602.6 MBOE, of which 81% was gas. These properties accounted for approximately 7,599 MBOE or 11% of our total estimated proved reserves at year end, of which 5,164 MBOE were proved developed and 2,434 MBOE were proved undeveloped. As of December 31, 2010, our Appalachian Basin properties consisted of 130,191 gross (65,559 net) acres.

Mississippi Properties

On May 20, 2010, we acquired our interest in properties located in the Mississippi Salt Basin. Most of our Mississippi properties are operated by Roundtree and Associates. Most of the production comes from the Parker Creek Field in Jones County, Mississippi, where our working interest is approximately 53%. Also in 2010, we purchased a license for 10 square miles of 3-D seismic data for the development of Parker Creek Field. Most of the production is oil that produces from the Hosston from a depth ranging from approximately 13,000 feet to 15,000 feet.
 
5

 
From May 20, 2010 through year end, the properties produced approximately 149.7 MBOE, of which 99% was oil.  These properties accounted for approximately 4,336 MBOE or 6% of our total estimated proved reserves at year end, of which 2,405 MBOE were proved developed and 1,931 MBOE were proved undeveloped. As of December 31, 2010, our Mississippi properties consisted of 2,560 gross (1,963 net) acres.

Big Horn Basin Properties

On December 31, 2010, we acquired an approximate 46.7% aggregate controlling interest in 24,512 gross and 20,400 net acres in the Big Horn Basin of northwestern Wyoming and south central Montana including the Elk Basin and Gooseberry fields through our subsidiary ENP. We also acquired and took over operatorship of (1) the Elk Basin natural gas processing plant near Powell, Wyoming, (2) the Clearfork crude oil pipeline extending from the South Elk Basin field to the Elk Basin field in Wyoming, (3) the Wildhorse natural gas gathering system that transports low sulfur natural gas from the Elk Basin and South Elk Basin fields to the Elk Basin natural gas processing plant, and (4) a small natural gas gathering system that transports high sulfur natural gas from the Elk Basin field to the Elk Basin natural gas processing facility.

The Big Horn Basin is characterized by oil and natural gas fields with long production histories and multiple producing formations. The Big Horn Basin is a prolific basin and has produced over 1.8 billion Bbls of oil since its discovery in 1906.

ENP’s properties in the Elk Basin area are located in the Elk Basin field, Northwest Elk Basin field, and the South Elk Basin field.  The Elk Basin assets had estimated proved reserves at December 31, 2010 of 18.3 MMBOE, of which 17.0 MMBOE were proved developed and 1.3 MMBOE were proved undeveloped.  ENP’s properties in the Elk Basin area include 17,075 gross acres (13,349 net) located in Park County, Wyoming and Carbon County, Montana.  ENP operates all properties in the Elk Basin area.  The major producing horizons in these fields are the Embar-Tensleep, Madison, Frontier, and Big Horn formations as discussed below.

Embar-Tensleep Formation.  Production in the Embar-Tensleep formation is being enhanced through a tertiary recovery technique involving effluent gas, or flue gas, from a natural gas processing facility located in the Elk Basin field. From 1949 to 1974, flue gas was injected into the Embar-Tensleep formation to increase pressure and improve production of resident hydrocarbons. Flue gas injection was re-established in 1998, and pressure monitoring wells indicate that the reservoir pressure continues to increase. ENP’s wells in the Embar-Tensleep formation of the Elk Basin field are drilled to a depth of 4,200 to 5,400 feet. ENP holds an average 62% working interest and an average 56% net revenue interest in these wells.  At December 31, 2010, the Embar-Tensleep formation had estimated total proved reserves of 5.4 MMBOE, all of which were oil and 95% of which were proved developed.

Madison Formation.  Production in the Madison formation is being enhanced through a waterflood. We believe that we can enhance production in the Madison formation by, among other things, reestablishing optimal injection and producing well patterns. The wells in the Madison formation of the Elk Basin field are drilled to a depth of 4,800 to 5,800 feet. ENP holds an average 67% working interest and an average 61% net revenue interest in these wells. The Madison formation had estimated total proved reserves at December 31, 2010 of 7.1 MMBOE, of which 99% were oil and 85% of which were proved developed.

Frontier Formation.  The Frontier formation is being produced through primary recovery techniques. The wells in the Frontier formation of the Elk Basin field are typically drilled to a depth of 1,600 to 2,900 feet. ENP holds an average 77% working interest and an average 68% net revenue interest in the wells in the Frontier formation. The Frontier formation had estimated total proved reserves at December 31, 2010 of 577 MBOE, 72% of which were oil and all of which were proved developed.

ENP also operates wells in the Northwest Elk Basin field and South Elk Basin field. ENP holds an average 65% working interest and an average 68 % net revenue interest in the wells in these fields. The Northwest Elk Basin field and South Elk Basin field had estimated total proved reserves at December 31, 2010 of 477 MBOE, 65% of which were oil and all of which were proved developed.

The Gooseberry field is made up of two waterflood units in the Big Horn Basin. The field is located 60 miles south of Elk Basin in Wyoming and consists of 26 active producing wells.  Gooseberry is an active waterflood project. The wells in the Gooseberry field are completed at 9,000 feet of depth from the Phosphoria and Tensleep formations. ENP holds all working interest and an average 90% net revenue interest in the wells in the Gooseberry field. The Gooseberry field had estimated proved reserves at December 31, 2010 of 4.5 MMBOE, all of which were oil and all of which were proved developed. ENP’s properties in the Gooseberry field include 7,437 gross acres (7,051 net) located in Park County and Hot Springs, Wyoming.

ENP operates and owns a 62% interest in the Elk Basin natural gas processing plant near Powell, Wyoming, which was first placed into operation in the 1940s. ExxonMobil Corporation owns a 34% interest in the Elk Basin natural gas processing plant, and other parties own the remaining 4% interest. This plant is a refrigeration natural gas processing plant that receives natural gas supplies through a natural gas gathering system from fields in the Elk Basin and South Elk Basin fields.
 
6

 
ENP owns and operates one crude oil pipeline system and two natural gas gathering pipeline systems in the Big Horn Basin. The Clearfork pipeline is regulated by the FERC and transports approximately 4,369 Bbls/day of crude oil from the Elk Basin field to a pipeline operated by Marathon Oil Corporation for further delivery to other markets. Most of the crude oil transported by the Clearfork pipeline is eventually sold to refineries in Billings, Montana. The Clearfork pipeline receives crude oil from various interconnections with local gathering systems. The Wildhorse pipeline system is an approximately 12-mile natural gas gathering system that transports approximately 1.3 MMcf/day of low-sulfur natural gas from the Elk Basin and South Elk Basin fields to the Elk Basin natural gas processing plant. The natural gas transported by the Wildhorse gathering system is sold into the WBI Pipeline. ENP also owns a small natural gas gathering system that transports approximately 14.0 MMcf/day of high sulfur natural gas from the Elk Basin field to the Elk Basin natural gas processing plant.

Williston Basin Properties

ENP’s Williston Basin properties include: Horse Creek, Charlson Madison Unit, Elk, Cedar Creek MT, Lookout Butte East, Pine, Beaver Creek, Buffalo Wallow, Buford, Crane, Charlie Creek, Dickinson, Elm Coulee, Lone Butte, Lonetree Creek, Missouri Ridge, Tracy Mountain, Tract Mountain Fryburg, Treetop, Trenton, and Whiskey Joe. ENP’s Williston Basin properties had estimated proved reserves at December 31, 2010 of 5.0 MMBOE, of which 4.5 MMBOE were proved developed and 0.5 MMBOE were proved undeveloped.

Arkoma Basin Properties

ENP’s Arkoma properties include royalty interests and non-operated working interest properties. The royalty interest properties include interests in over 1,700 wells in Arkansas, Texas, and Oklahoma as well as 10,300 unleased mineral acres. The non-operated working interest properties include interests in over 100 producing wells in the Chismville field. At December 31, 2010, the properties had total proved reserves of approximately 1.4 MMBOE, all of which were proved developed and 87% of which were natural gas.
 
 
Oil, Natural Gas and Natural Gas Liquids Prices
 
 
The Appalachian Basin is a mature, producing region with well known geologic characteristics. Reserves in the Appalachian Basin typically have a high degree of step-out development success; that is, as development progresses, reserves from newly completed wells are reclassified from the proved undeveloped to the proved developed category, and additional adjacent locations are added to proved undeveloped reserves. As a result, the cumulative amount of total proved reserves tends to increase as development progresses. Wells in the Appalachian Basin generally produce little or no water, contributing to a low cost of operation. 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, 2010, 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 $0.14 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, 2010, our average realized natural gas prices in Appalachia (before hedging), represented a $1.15 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 the sale of natural gas liquids resulting from such processing, depending on the terms of the various agreements. For the year ended December 31, 2010, the average premium over NYMEX from the sale of casinghead gas plus our share of the revenues from the sale of natural gas liquids was $0.41 per MMBtu.

In South Texas, our natural gas production has a high Btu content and requires processing prior to sale to third parties. Through our relationship with the operator of the Dos Hermanos and Sun TSH properties, an affiliate of 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. During 2010, we received the average WTI price less $12.79 per barrel in Appalachia and the average WTI price less $4.43 per barrel in the Permian Basin.
 
7

 
We enter into derivative transactions in the form of hedging arrangements to reduce the impact of oil and natural gas price volatility on our cash flow from operations. Currently, we use fixed-price swaps, swaptions, put options and NYMEX collars to hedge oil and natural gas prices. By removing the price volatility from a significant portion of our oil and natural gas production, we have mitigated for a period of time, but not eliminated, the potential effects of fluctuation in oil and natural gas 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.”
 
 
Oil, Natural Gas and Natural Gas Liquids Data

 
Estimated Proved Reserves
 
The following table presents our estimated net proved oil, natural gas and natural gas liquids reserves and the present value of the estimated proved reserves at December 31, 2010, based on reserve reports prepared by D&M. Copies of their summary reports are included as exhibits to this Annual Report. Our estimated proved reserves and productive wells at December 31, 2010 include those proved reserves that we acquired in connection with the Encore Acquisition and are subject to a 53.3% non-controlling interest in ENP. 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 oil, natural gas and natural gas liquids reserves.
 
   
 
As of December 31, 2010
 
VNR
 
ENP (1)
 
Total
Reserve Data:
             
Estimated net proved reserves:
             
Crude oil (MBbls)
 
10,678
 
27,443
 
38,121
 
Natural gas (Bcf)
 
79.4
 
74.5
 
153.9
 
Natural gas liquids (MBbls)
 
4,298
 
1,210
 
5,508
 
Total (MMBOE)
 
28.2
 
41.1
 
69.3
 
Proved developed (MMBOE)
 
18.7
 
37.0
 
55.7
 
Proved undeveloped (MMBOE)
 
9.5
 
4.1
 
13.6
 
Proved developed reserves as % of total proved reserves
 
66
%
90
%
80
%
Standardized Measure (in millions) (2)
$
414.9
 
$
703.5
 
$
1,118.4
 
Representative Oil and Natural Gas Prices (3):
             
Oil—WTI per Bbl
$
79.40
 
$
79.43
       
Natural gas—Henry Hub per MMBtu
$
4.38
 
$
4.45
       
 
 
(1)   Includes the non-controlling interest of approximately 53.3% as of December 31, 2010.

 
(2)   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.”
 
 
(3)   Oil and natural gas prices are based on spot prices per Bbl and MMBtu, respectively, calculated using the 12-month unweighted average of first-day-of-the-month price (the “12-month average price”) for January through December 2010, with these representative prices adjusted by field for quality, transportation fees and regional price differentials to arrive at the appropriate net price.
 
 
8

 
The following tables set forth certain information with respect to our estimated proved reserves by operating area as of December 31, 2010 based on estimates made in a reserve report prepared by D&M.
 
   
Estimated Proved Developed
Reserve Quantities
   
Estimated Proved Undeveloped
Reserve Quantities
   
Estimated Proved Reserve Quantities
 
   
Natural Gas
   
Oil
   
NGLs
   
Total
   
Natural Gas
   
Oil
   
NGLs
   
Total
   
Total
 
   
(Bcf)
   
(MMBbls)
   
(MMBbls)
   
(MMBOE)
   
(Bcf)
   
(MMBbls)
   
(MMBbls)
   
(MMBOE)
   
(MMBOE)
 
Operating Area
                                                     
VNR Properties:
                                                     
  Permian Basin
    3.1       4.6       0.4       5.5       1.3       1.4       0.3       1.9       7.4  
  South Texas
    19.4       0.1       2.3       5.6       11.2       0.1       1.3       3.3       8.9  
  Appalachian Basin
    28.9       0.3             5.2       14.6                   2.4       7.6  
  Mississippi
    0.9       2.3             2.4             1.9             1.9       4.3  
ENP Properties: (2)
                                                                       
  Permian Basin
    54.8       5.0             14.1       7.3       1.1             2.3       16.4  
  Big Horn Basin
    2.2       15.5       1.2       17.0             1.3             1.3       18.3  
  Williston Basin
    2.7       4.0             4.5       0.2       0.5             0.5       5.0  
  Arkoma Basin
    7.3       0.2             1.4                               1.4  
Total
    119.3       32.0       3.9       55.7       34.6       6.3       1.6       13.6       69.3  
 
 
   
PV10 Value (1)
 
Operating Area
 
Developed
   
Undeveloped
   
Total
 
   
(in millions)
 
VNR Properties:
                       
  Permian Basin
 
$
121.4
   
$
25.3
   
$
146.7
 
  South Texas
   
59.9
     
20.8
     
80.7
 
  Appalachian Basin
   
54.0
     
(2.7
   
51.3
 
  Mississippi
   
77.2
     
59.0
     
136.2
 
ENP Properties: (2)
                       
  Permian Basin
   
159.4
     
17.7
     
177.1
 
  Big Horn Basin
   
387.2
     
26.1
     
413.3
 
  Williston Basin
   
88.4
     
6.2
     
94.6
 
  Arkoma Basin
   
18.5
     
     
18.5
 
                         
Total
 
$
966.0
   
$
152.4
   
$
1,118.4
 
 
 
(1)
 
PV10 is not a measure of financial or operating performance under GAAP, nor should it be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows as defined under GAAP. However, for Vanguard, PV10 is equal to the standardized measure of discounted future net cash flows under GAAP because the Company is not a tax paying entity. For our presentation of the standardized measure of discounted future net cash flows, please see “Supplemental Oil and Natural Gas Information” in the Notes to the Consolidated Financial Statements in Part II, Item 8 in this Annual Report on Form 10-K.
(2)
 
Includes the non-controlling interest of approximately 53.3% as of December 31, 2010.
 
The data in the above tables represent estimates only. Oil, natural gas and natural gas liquids and oil reserve engineering is inherently a subjective process of estimating underground accumulations of oil, natural gas and natural gas liquids that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. The quantities of oil, natural gas and natural gas liquids that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future sales prices may differ from those assumed in these estimates. Please read “Item 1A—Risk Factors.”
 
In accordance with the guidelines of the SEC, our independent reserve engineers’ estimates of future net revenues from our properties, and the standardized measure thereof, were determined to be economically producible under existing economic conditions, which requires the use of the 12-month average price for each product.

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’s (“FASB”) Accounting Standards Codification (“ASC”), 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 reserve engineers to prepare a reserve and economic evaluation of properties that we are considering purchasing. Neither the reserve engineers nor any of their respective employees have 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 2010, we paid Netherland, Sewell & Associates, Inc. and DeGolyer and MacNaughton approximately $50,000 and $25,000, respectively, for all reserve and economic evaluations.
 
9

 
Proved Undeveloped Reserves

Our proved undeveloped reserves at December 31, 2010, as estimated by our independent petroleum engineers, were 13.6 MMBOE, consisting of 6.3 million barrels of oil, 34.6 MMcf of natural gas and 1.6 million barrels of natural gas liquids. Our proved undeveloped reserves increased by 5.9 MMBOE during the year ended December 31, 2010, due to the acquisition of 4.1 MMBOE and 1.9 MMBOE total proved undeveloped reserves in connection with the Encore and Parker Creek acquisitions, respectively, which was offset by the development of 1.5% of our total proved undeveloped reserves booked as of December 31, 2009 through the drilling of two gross (1.5 net) well at an aggregate capital cost of approximately $7.8 million. The proved undeveloped reserves that we acquired in connection with the Encore Acquisition are subject to a 53.3% non-controlling interest in ENP.

None of our proved undeveloped reserves at December 31, 2010 have remained undeveloped for more than five years since the date of initial booking as proved undeveloped reserves. At December 31, 2010, there are 6 locations with 0.3 MMBOE of proved undeveloped reserves in South Texas that are scheduled to be drilled on a date more than five years from the date the reserves were initially booked as proved undeveloped.

At December 31, 2010, all of our leases are held by production, with the exception of 955 acres in Ward County, Texas that will expire in September of 2011. We anticipate that we will drill in this acreage prior to the lease expiration date.

Qualifications of Technical Persons and Internal Controls over Reserves Estimation Process

Our proved reserve information as of December 31, 2010 included in this Annual Report was estimated by our independent petroleum engineers, D&M, in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserve Information promulgated by the Society of Petroleum Engineers and definitions and guidelines established by the SEC.

Our Senior Vice President of Operations, Britt Pence, is the person primarily responsible for overseeing the preparation of our internal reserve estimates and for the coordination of the third-party reserve reports provided by D&M. Mr. Pence has over 27 years of experience and is a graduate of Texas A&M University with a Bachelor of Science degree in Petroleum Engineering. He is a member of the Society of Petroleum Engineers. Prior to joining us in 2007, Mr. Pence held engineering and managerial positions with Anadarko Petroleum Corporation, Greenhill Petroleum Company and Mobil Oil Corporation.

Within D&M, the technical person primarily responsible for preparing the estimates set forth in the D&M report letter is Mr. Paul J. Szatkowski. Mr. Szatkowski is a Senior Vice President with D&M and has over 35 years of experience in oil and gas reservoir studies and reserves evaluations. He graduated from Texas A&M University in 1974 with a Bachelor of Science Degree in Petroleum Engineering and is a member of the International Society of Petroleum Engineers and the American Association of Petroleum Geologists. Mr. Szatkowski meets or exceeds the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers and is proficient in applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.

The technical persons responsible for preparing the reserves estimates presented herein meet the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers.

We maintain an internal staff of petroleum engineers who work closely with our independent petroleum engineers to ensure the integrity, accuracy and timeliness of data furnished to D&M in their reserves estimation process. In the fourth quarter, our technical team met on a regular basis with representatives of D&M to review properties and discuss methods and assumptions used in D&M’s preparation of the year-end reserves estimates. All field and reserve technical information, which is updated annually, is assessed for validity when D&M hold technical meetings with our internal staff of petroleum engineers, operations and land personnel to discuss field performance and to validate future development plans. While we have no formal committee specifically designated to review reserves reporting and the reserves estimation process, the D&M reserve report is reviewed by our senior management and internal technical staff.

Reserve Technologies

Proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and/or natural gas actually recovered will equal or exceed the estimate. To achieve reasonable certainty, D&M employed technologies that have been demonstrated to yield results with consistency and repeatability. The technical and economic data used in the estimation of our proved reserves include, but are not limited to, well logs, geologic maps, production data, seismic data, well test data, historical price and cost information and property ownership interests.
 
10

 
 
Production and Price History
 
 
The following table sets forth information regarding net production of oil, natural gas and natural gas liquids and certain price and cost information for each of the periods indicated. No production results are included for properties acquired on December 31, 2010 related to the Encore Acquisition. 
 
     
Net Production
 
Average Realized Sales Prices (3)
 
Production Cost (4)
   
Crude Oil
Bbls/day
Natural Gas Mcf/day
NGLs
Gal/day
Crude Oil Per Bbl
Natural Gas Per Mcf
NGLs Per Gal
Per BOE
Year Ended December 31, 2010 (1)
               
Sun TSH Field
   
40
2,586
15,025
$
75.74
$
7.59
$
1.14
$
5.77
Other
   
1,830
11,086
9,086
$
76.54
$
10.45
$
0.99
$
11.77
Total
   
1,870
13,672
24,111
$
76.53
$
9.91
$
1.09
$
10.72
                           
Year Ended December 31, 2009 (2)
                         
Sun TSH Field
   
26
1,124
7,095
$
65.40
$
11.03
$
0.95
$
3.76
Other
   
921
11,320
6,113
$
75.54
$
11.16
$
0.75
$
11.25
Total
   
947
12,444
13,208
$
75.26
$
11.15
$
0.86
$
10.39
                           
Year Ended December 31, 2008 (5)
                         
Total other
   
715
11,450
3,271
 $
85.69
 $
10.49
$
1.18
$
11.24
 
 
(1)        Average daily production for 2010 calculated based on 365 days including production for the Parker Creek acquisition from the closing date of this acquisition.

 
(2)        Average daily production for 2009 calculated based on 365 days including production for the Sun TSH and Ward County acquisitions from the closing dates of these acquisitions.

 
(3)        Average realized sales prices including hedges but excluding the non-cash amortization of premiums paid and non-cash amortization of value on derivative contracts acquired.
 
 
  (4)   Production costs include such items as lease operating expenses, which include transportation charges, gathering and compression fees and other customary charges and exclude production taxes (severance and ad valorem taxes).
 
   
  (5)   Average daily production for 2008 calculated based on 366 days including production for the Permian Basin and Dos Hermanos acquisitions from the closing dates of these acquisitions.

 
Productive Wells
 
 
The following table sets forth information at December 31, 2010 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
   
Total
 
   
Gross
   
Net
   
Gross
   
Net
   
Gross
   
Net
 
VNR Properties:
                                   
  Permian Basin
                877       130       877       130  
  South Texas
    208       204                   208       204  
  Appalachian Basin
    1,025       886                   1,025       886  
  Mississippi
                20       8       20       8  
ENP Properties:
                                               
  Permian Basin
    562       274       1,542       379       2,104       653  
  Big Horn Basin
    41       30       353       272       394       302  
  Williston Basin
    23       6       106       70       129       76  
  Arkoma Basin
    129       10       9       1       138       11  
Total
    1,988       1,410       2,907       860       4,895       2,270  
 
 
11

 
 
Developed and Undeveloped Acreage
 
 
The following table sets forth information as of December 31, 2010 relating to our leasehold acreage.
 
     
Developed Acreage (1)
     
Undeveloped Acreage (2)
     
Total Acreage
 
   
Gross (3)
   
Net (4)
   
Gross (3)
   
Net (4)
   
Gross (3)
   
Net (4)
 
VNR Properties:
                                   
  Permian Basin
    12,907       8,944       3,350       2,760       16,257       11,704  
  South Texas
    8,480       8,262       12,540       6,005       21,020       14,267  
  Appalachian Basin
    20,900       18,966       109,291       46,593       130,191       65,559  
  Mississippi
    2,560       963                   2,560       963  
ENP Properties: (5)
                                               
  Permian Basin
    59,617       37,612       4,036       5,099       63,653       42,711  
  Big Horn Basin
    23,392       19,327       1,120       1,073       24,512       20,400  
  Williston Basin
    39,870       31,689       9,859       6,595       49,729       38,284  
  Arkoma Basin
    3,192       411       357       84       3,549       495  
Total
    170,918       126,174       140,553       68,209       311,471       194,383  
 
 
(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 oil or natural gas, 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.
 
 
 
(5)        Includes the non-controlling interest of approximately 53.3% as of December 31, 2010.

 
Drilling Activity

In Appalachia, most of our wells are drilled to depths ranging from 2,000 feet to 4,500 feet.  Many of our wells are completed to multiple producing zones and production from these zones may be commingled.  The average well in Appalachia takes approximately 10 days to drill and most of our wells are producing and connected to 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.  In 2009 and 2010, we and our operating partner, Vinland, decided not to drill any new gas wells until natural gas prices improve. However, during 2010 we drilled nine oil wells and completed four wells targeting oil zones less than 3,000 feet. At year end 2010, five of these wells were awaiting completion, expected in 2011.We plan to drill an additional 12 oil wells in 2011.

In the Permian Basin, we drilled one Vanguard operated horizontal oil well in the 3rd Bone Spring sand in Ward County, Texas. This well was drilled to a vertical depth of approximately 11,400 feet with an approximate 4,000 feet lateral and completed with a 7 stage fracture stimulation job. The well’s initial production was over 500 barrels of oil equivalent per day. There were five proved undeveloped and two probable horizontal Bone Spring wells remaining to drill at year end 2010. In 2011, we plan to drill two horizontal Bone Spring wells.

In South Texas, most of our wells are drilled to depths ranging from 5,500 feet to 7,800 feet. Most of the reserves are produced from the Olmos gas sands. In 2010, we participated in the drilling of one horizontal Olmos well in Webb County, Texas with a 45% working interest. The well initially produced 1.2 MMcfd. In 2011, we plan to drill four vertical Olmos and Escondido gas wells in La Salle County, Texas with a 50% working interest.
 
12

 
In Mississippi, we participated in the drilling of one 13,886 foot Hosston oil well in the Parker Creek Field with an approximate 53% working interest. The well initially produced over 100 barrels of oil per day. In 2011, we plan to drill two Hosston oil wells in the Parker Creek Field with an approximate 53% working interest.

During 2011, we intend to concentrate our drilling on low risk, development opportunities with the majority of drilling capital focused on oil wells. Excluding any potential acquisitions, we currently anticipate a capital budget for 2011 of between $27.0 million and $28.5 million, which includes anticipated expenditures for VNR and our 46.7% aggregate controlling interest in ENP. VNR’s stand alone capital budget is expected to be between $17.9 and $18.7 million and will largely include oil focused drilling in our Bone Springs play in the Permian Basin and the Hosston formation in Mississippi. The remaining $9.1 to $9.8 million represents our net interest in capital spending for Encore which will focus primarily on oil drilling in the Big Horn Basin and a variety of recompletion projects in the Permian Basin.
 
The following table sets forth information with respect to wells completed during the years ended December 31, 2010, 2009 and 2008. 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. The following table does not include any drilling activity associated with the Encore Acquisition completed on December 31, 2010.
 
   
Year Ended December 31,
 
   
2010
   
2009
   
2008
 
Gross wells:
                 
Productive
    8       1       86  
Dry
                1  
Total
    8       1       87  
Net Development wells:
                       
Productive
    4.6       0.45       38  
Dry
                1  
Total
    4.6       0.45       39  
Net Exploratory wells:
                       
Productive
                 
Dry
                 
Total
                 

 
Operations
 
 
Principal Customers
 
 
For the year ended December 31, 2010, sales of oil, natural gas and natural gas liquids to Seminole Energy Services, Plains Marketing L.P., Shell Trading (US) Company, Osram Sylvania, Inc., and Occidental Energy Marketing, Inc. accounted for approximately 20%, 19%, 11%, 5% and 4%, respectively, of our oil, natural gas and natural gas liquids revenues. Our top five purchasers during the year ended December 31, 2010, therefore accounted for 59% of our total revenues. To the extent these and other customers reduce the volumes of oil, natural gas and natural gas liquids 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.

 
Delivery Commitments and Marketing Arrangements

Our oil and natural gas production is principally sold to marketers, processors, refiners, and other purchasers that have access to nearby pipeline, processing, and gathering facilities. In areas where there is no practical access to pipelines, oil is trucked to central storage facilities where it is aggregated and sold to various markets and downstream purchasers. Our production sales agreements generally contain customary terms and conditions for the oil and natural gas industry, provide for sales based on prevailing market prices in the area, and generally are month-to-month or have terms of one year or less. As of December 31, 2010, we did not have any ongoing delivery commitments of fixed and determinable quantities of oil or natural gas.

We generally sell our natural gas production from our operated properties on the spot market or under market-sensitive, short-term agreements with purchasers, including the marketing affiliates of intrastate and interstate pipelines, independent marketing companies, gas processing companies, and other purchasers who have the ability to pay the highest price for the natural gas production and move the natural gas under the most efficient and effective transportation agreements. Because all of our natural gas production from our operated properties is sold under market-priced agreements, we are positioned to take advantage of future increases in natural gas prices, but we are also subject to any future price declines. We do not market our own natural gas on our non-operated Permian Basin properties, but receive our share of revenues from the operator.
 
13

 
The marketing of our Big Horn heavy sour crude oil production is through our Clearfork pipeline, which transports the crude oil to local and other refiners through connections to other interstate pipelines. Our Big Horn sweet crude oil production is transported from the field by a third party trucking company that delivers the crude oil to a centralized facility connected to a common carrier pipeline with delivery points accessible to local refiners in the Salt Lake City, Utah and Guernsey, Wyoming market centers. We sell oil production from our operated Permian Basin at the wellhead to third party gathering and marketing companies. Any restrictions on the available capacity to transport oil through any of the above mentioned pipelines, or any other pipelines, or any interruption in refining throughput capacity could have a material adverse effect on our production volumes and the prices we receive for our production.

 
Price Risk and Interest Rate Management Activities
 
 
We enter into derivative contracts with respect to a portion of our projected oil and natural gas 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. In addition, we sell calls or provide options to counterparties under swaption agreements to extend the swaps into subsequent years. Additionally, we may enter into 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 oil and natural gas 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 tables summarize commodity derivative contracts in place at December 31, 2010:
 
   
Year
2011
   
Year
2012
   
Year
2013
   
Year
2014
 
Gas Positions:
                       
Fixed Price Swaps:
                       
VNG
                       
Notional Volume (MMBtu)
    3,328,312                    
Fixed Price ($/MMBtu)
  $ 7.83     $     $     $  
ENP
                               
Notional Volume (MMBtu)
    3,723,730       3,367,932       2,993,000        
Fixed Price ($/MMBtu)
  $ 6.06     $ 5.75     $ 5.10     $  
Consolidated
                               
Notional Volume (MMBtu)
    7,052,042       3,367,932       2,993,000        
Fixed Price ($/MMBtu)
  $ 6.89     $ 5.75     $ 5.10     $  
Collars:
                               
VNG
                               
Notional Volume (MMBtu)
    1,933,500                    
Floor Price ($/MMBtu)
  $ 7.34     $     $     $  
Ceiling Price ($/MMBtu)
  $ 8.44     $     $     $  
Puts:
                               
ENP
                               
Notional Volume (MMBtu)
    1,240,270       328,668              
Fixed Price ($/MMBtu)
  $ 6.31     $ 6.76     $     $  
Total Gas Positions:
                               
VNG
                               
Notional Volume (MMBtu)
    5,261,812                    
ENP
                               
Notional Volume (MMBtu)
    4,964,000       3,696,600       2,993,000        
Consolidated
                               
Notional Volume (MMBtu)
    10,225,812       3,696,600       2,993,000        

 
 
14

 

 
   
Year
2011
   
Year
2012
   
Year
2013
   
Year
2014
 
Oil Positions:
             
 
       
Fixed Price Swaps:
                       
VNG
                       
Notional Volume (Bbls)
    443,250       347,700       296,400       209,875  
Fixed Price ($/Bbl)
  $ 87.94     $ 90.03     $ 89.84     $ 94.37  
ENP
                               
Notional Volume (Bbls)
    523,775       947,940       1,295,750       1,168,000  
Fixed Price ($/Bbl)
  $ 79.48     $ 82.05     $ 88.95     $ 88.95  
Consolidated
                               
Notional Volume (Bbls)
    967,025       1,295,640       1,592,150       1,377,875  
Fixed Price ($/Bbl)
  $ 83.36     $ 84.19     $ 89.11     $ 89.78  
Collars:
                               
VNG
                               
Notional Volume (Bbls)
          45,750       45,625        
Floor Price ($/Bbl)
  $     $ 80.00     $ 80.00     $  
Ceiling Price ($/Bbl)
  $     $ 100.25     $ 100.25     $  
ENP
                               
Notional Volume (Bbls)
    525,600       274,500              
Floor Price ($/Bbl)
  $ 73.06     $ 68.33     $     $  
Ceiling Price ($/Bbl)
  $ 95.41     $ 81.12     $     $  
Consolidated
                               
Notional Volume Bbls)
    525,600       320,250       45,625        
Floor Price ($/Bbl)
  $ 73.06     $ 70.00     $ 80.00     $  
Ceiling Price ($/Bbl)
  $ 95.41     $ 83.85     $ 100.25     $  
Puts:
                               
ENP
                               
Notional Volume (Bbls)
    803,000       552,660              
Floor Price ($/Bbls)
  $ 74.82     $ 65.83     $     $  
Total Oil Positions:
                               
VNG
                               
Notional Volume (Bbls)
    443,250       393,450       342,025       209,875  
ENP
                               
Notional Volume (Bbls)
    1,852,375       1,775,100       1,295,750       1,168,000  
Consolidated
                               
Notional Volume (Bbls)
    2,295,625       2,168,550       1,637,775       1,377,875  
 
 
15

 
 
Calls were sold or options provided to counterparties under swaption agreements to extend the swaps into subsequent years as follows:
 
   
Year
 2012
   
Year
2013
   
Year
2014
   
Year
2015
 
Swaptions:
                       
Notional Volume (Bbls)
    45,750       32,100       127,750       292,000  
Weighted Average Fixed Price ($/Bbl)
  $ 90.40     $ 95.00     $ 95.00     $ 95.63  

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 obligations to fixed interest rates.
 
The following summarizes information concerning our positions in open interest rate swaps at December 31, 2010 (in thousands):
 
   
   Notional Amount
 
Fixed Libor Rates
 
Period:
             
VNG
             
January 1, 2011 to March 31, 2011
 
$
20,000
   
2.08
%
January 1, 2011 to December 10, 2012
 
$
20,000
   
3.35
%
January 1, 2011 to January 31, 2013
 
$
20,000
   
2.38
%
January 1, 2011 to January 31, 2013
 
$
20,000
   
2.66
%
August 6, 2012 to August 6, 2014
 
$
25,000
   
2.09
%
August 6, 2012 to August 5, 2015 (1)
 
$
30,000
   
2.25
%
ENP
             
January 1, 2011 to January 31, 2011
 
$
50,000
   
3.16
%
January 1, 2011 to January 31, 2011
 
$
25,000
   
2.97
%
January 1, 2011 to January 31, 2011
 
$
25,000
   
2.96
%
January 1, 2011 to March 31, 2012
 
$
50,000
   
2.42
%

 
(1)
The counterparty has the option to extend the termination date of this contract to August 5, 2018.

 Counterparty Risk

At December 31, 2010, 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 S&P financial strength rating in parentheses (in thousands):

   
Current Assets
   
Current Liabilities
   
Long-Term Assets
   
Long-Term Liabilities
   
Total Amount Due From/(Owed To) Counterparty at December 31, 2010
 
Citibank, N.A. (A+)
  $ 5,197     $     $     $ (441 )   $ 4,756  
Wells Fargo Bank N.A./Wachovia Bank, N.A. (AA)
    182       (438 )     2,001       (5,435 )     (3,690 )
BNP Paribas (AA)
    10,992       (7,530 )     919       (10,257 )     (5,876 )
The Bank of Nova Scotia (AA-)
    1,325       (478 )           (4,768 )     (3,921 )
BBVA Compass (A)
          (142 )           (253 )     (395 )
Credit Agricole (AA-)
    4,391       (3,695 )     1,912       (4,604 )     (1,996 )
Royal Bank of Canada (AA-)
    2,028       (302 )     1,297       (9,050 )     (6,027 )
Bank of America (A+)
          (1,216 )           (226 )     (1,442 )
Total
  $ 24,115     $ (13,801 )   $ 6,129     $ (35,034 )   $ (18,591 )


 
16

 
In order to mitigate the credit risk of financial instruments, we enter into master netting agreements with our counterparties. The master netting agreement is a standardized, bilateral contract between a given counterparty and us. Instead of treating each financial transaction between the counterparty and us separately, the master netting agreement enables the counterparty and us to aggregate all financial trades and treat them as a single agreement. This arrangement is intended to benefit us in two ways: (1) default by a counterparty under one financial trade can trigger rights to terminate all financial trades with such counterparty; and (2) netting of settlement amounts reduces our credit exposure to a given counterparty in the event of close-out.
 
 
Competition
 
 
The oil and natural gas 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 oil and natural gas industry has experienced shortages of drilling rigs, equipment, pipe and personnel, which has delayed development drilling 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 program.
 
Competition is also strong for attractive oil and 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 oil and natural gas 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 oil and natural gas leases, we perform title reviews on the most significant leases and, depending on the materiality of properties, we may obtain a title opinion or review previously obtained title opinions. As a result, we have obtained title opinions on a significant portion of our oil and natural gas properties and believe that we have satisfactory title to our producing properties in accordance with standards generally accepted in the oil and natural gas industry. Although title to these properties is subject to encumbrances in some cases, such as customary interests generally retained in connection with acquisition of real property, customary royalty interests, contract terms and restrictions, liens under operating agreements, liens related to environmental liabilities associated with historical operations, liens for taxes not yet payable and other burdens, restrictions and minor encumbrances customary in the oil and natural gas industry, we believe that none of these liens, restrictions, easements, burdens and encumbrances will materially detract from the value of these properties or from our interest in these properties, or will materially interfere with our use of these properties in the operation of our business.
 
 
Natural Gas Gathering
 
 
ENP owns and operates a network of natural gas gathering systems in the Big Horn Basin area of operation. These systems gather and transport their natural gas and a small amount of third-party natural gas to larger gathering systems and intrastate, interstate, and local distribution pipelines. Their network of natural gas gathering systems permits them to transport production from their wells with fewer interruptions and also minimizes any delays associated with a gathering company extending its lines to their wells. Their ownership and control of these lines enables them to:
 
17

 
·      realize faster connection of newly drilled wells to the existing system;
 
·
control pipeline operating pressures and capacity to maximize their production;
 
·
control compression costs and fuel use;
 
·
maintain system integrity;
 
·
control the monthly nominations on the receiving pipelines to prevent imbalances and penalties; and
 
·
track sales volumes and receipts closely to assure all production values are realized.

The gas gathering systems were operated for ENP by Encore Operating during 2010 pursuant to an administrative services agreement. During 2011, VNG will operate their gas gathering systems pursuant to the Services Agreement.

 
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 and as a result, we generally perform the majority of our drilling in these areas 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, oil is typically in higher demand in the summer for its use in road construction and natural gas is in higher demand in the winter for heating. Seasonal anomalies such as mild winters or hot summers sometimes lessen this fluctuation. In addition, certain natural gas consumers utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer. This can also lessen seasonal demand fluctuations.
 
 
Environmental, Health and Safety Matters
 
 
General.   Our business involving the acquisition and development of oil and natural gas properties is subject to extensive and stringent federal, state and local laws and regulations governing the discharge of materials into the environment, conservation and environmental protection, and occupational health and safety. These operations are subject to the same environmental, health and safety laws and regulations as other similarly situated companies in the oil and natural gas 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 and performance of costly remedial measures to mitigate or prevent pollution from historical and ongoing operations, such as pit closure and plugging of abandoned wells;
     
 
·
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;
     
 
·
impose specific health and safety criteria addressing worker protection;
     
 
·
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.
 
    
 
      
Failure to comply with these laws and regulations may result in assessment of administrative, civil and criminal penalties, imposition of removal or remedial obligations, and the issuance of orders enjoining some or all of our operations deemed in non-compliance. Moreover, these laws and regulations may restrict our ability to produce oil, natural gas and natural gas liquids by, among other things, limiting production 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 oil and natural gas 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 oil and natural gas 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 existing or newly adopted environmental laws and regulations may impact our properties or the operations. For the year ended December 31, 2010, 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 2011 or that will otherwise have a material impact on our financial position or results of operations.
 
18

 
The following is a summary of the more significant existing environmental and occupational health and safety laws to which our business operations are subject and for which compliance may have a material impact on our operations as well as the oil and natural gas exploration and production industry in general.
 
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. Although we do not believe the current costs of managing wastes generated by operation of our wells to be significant, any legislative or regulatory reclassification of oil and natural gas 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 certain classes of 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 found 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 oil and natural gas 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 these substances, wastes and hydrocarbons have been taken for treatment or 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.

ENP’s Elk Basin assets include a natural gas processing plant. Previous environmental investigations of the Elk Basin natural gas processing plant indicate historical soil and groundwater contamination by hydrocarbons and the presence of asbestos-containing material at the site. Although the environmental investigations did not identify an immediate need for remediation of the suspected historical hydrocarbon contamination or abatement of the asbestos, the extent of the hydrocarbon contamination is not known and, therefore, the potential liability for remediating this contamination may be significant. In the event we ceased operating the gas plant, the cost of decommissioning it and addressing the previously identified environmental conditions and other conditions, such as waste disposal, could be significant. We do not anticipate ceasing operations at the Elk Basin natural gas processing plant in the near future nor a need to commence remedial activities at this time. However, a regulatory agency could require us to investigate and remediate any hydrocarbon contamination even while the gas plant remains in operation. As of December 31, 2010, we have recorded $10.1 million as future abandonment liability for the estimated cost for decommissioning the Elk Basin natural gas processing plant. Due to the significant uncertainty associated with the known and unknown environmental liabilities at the gas plant, our estimate of the future abandonment liability includes a large reserve. Our estimates of the future abandonment liability and compliance costs are subject to change and the actual cost of these items could vary significantly from those estimates.
 
Water.   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 oil and natural gas 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.
 
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The primary federal law for oil spill liability is the Oil Pollution Act (“OPA”), which addresses three principal areas of oil pollution—prevention, containment, and cleanup. OPA applies to vessels, offshore facilities, and onshore facilities, including exploration and production facilities that may affect waters of the United States. Under OPA, responsible parties, including owners and operators of onshore facilities, may be held strictly liable for oil cleanup costs and natural resource damages as well as a variety of public and private damages that may result from oil spills.

Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations, including shales. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and gas commissions.  However, the EPA recently asserted federal regulatory authority over hydraulic fracturing involving diesel additives under the federal Safe Drinking Water Act’s Underground Injection Program. While the EPA has yet to take any action enforce or implement this newly asserted regulatory authority, industry groups have filed suit challenging the EPA’s recent decision. At the same time, the EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities, with results of the study anticipated to be available by late 2012, and a committee of the U.S. House of Representatives is also conducting an investigation of hydraulic fracturing practices. In addition, legislation was proposed in the recently ended session of Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process, and such legislation could be introduced in the current session of Congress. Also, some states have adopted, and other states are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances or otherwise require the public disclose of chemicals used in the hydraulic fracturing process. For example, Wyoming, where we pursue development of natural gas, has adopted legislation requiring drilling operators conducting hydraulic fracturing activities in that state to publicly disclose the chemical used in the hydraulic fracturing process. If new federal or state laws or regulations that significantly restrict hydraulic fracturing are adopted, such legal requirements could increase our costs of compliance and delay or reduce demand for the oil and natural gas we produce.

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.

Activities on Federal Lands.  Oil and natural gas 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 production activities, as well as proposed 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 increase the cost of developing oil and natural gas projects.

In response to findings that emissions of carbon dioxide, methane, and other greenhouse gases, or  “GHGs,” present an endangerment to public health and the environment because emissions of such gasses are contributing to the warming of the earth’s atmosphere and other climate changes, the U.S. Environmental Protection Agency, or “EPA,” has adopted regulations under existing provisions of the federal Clean Air Act that require a reduction in emissions of GHGs from motor vehicles effective January 2, 2011 and thereby triggered construction and operating permit review for GHG emissions from certain stationary sources. The EPA has published its final rule to address the permitting of GHG emissions from stationary sources under the Prevention of Significant Deterioration, or “PSD,” and Title V permitting programs, pursuant to which these permitting programs have been “tailored” to apply to certain stationary sources of GHG emissions in a multi-step process, with the largest sources first subject to permitting. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards, which will be established by the states or, in some instances, by the EPA on a case-by-case basis. The EPA’s rules relating to emissions of GHGs from large stationary sources of emissions are currently subject to a number of legal challenges but the federal courts have thus far declined to issue any injunctions to prevent EPA from implementing or requiring state environmental agencies to implement the rules. These EPA rulemakings could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified facilities. With regards to the monitoring and reporting of GHGs, on November 30, 2010, the EPA published a final rule expanding its existing GHG emissions reporting rule published in October 2009 to include onshore and offshore oil and natural gas production and onshore oil and natural gas processing, transmission, storage, and distribution activities, which may include certain of our operations, beginning in 2012 for emissions occurring in 2011.
 
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In addition, Congress has from time to time considered legislation to reduce emissions of GHGs, and almost one-half of the states have already taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs.  Most of these cap and trade programs work by requiring either major sources of emissions or major producers of fuels to acquire and surrender emission allowances, with the number of allowances available for purchase reduced each year until the overall GHG emission reduction goal is achieved. These allowances would be expected to escalate significantly in cost over time. The adoption of legislation or regulations that requires reporting of GHGs or otherwise limits emissions of GHGs from our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations or could adversely affect demand for the oil and natural gas that we produce. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events; if any such effects were to occur, they could have an adverse effect on our operations.

Occupational Safety and Health.  We are subject to the requirements of the federal Occupational Safety and Health Act, as amended, or “OSHA,” and comparable state statutes, whose purpose is to protect the health and safety of workers. In addition, the OSHA hazard communication standard, EPA community right-to-know regulations under the Title III of CERCLA and similar state statutes require that we maintain and/or disclose information about hazardous materials used or produced in our operations and that this information be provided to employees, state and local governmental authorities and citizens.
  
 
Other Regulation of the Oil and Natural Gas Industry
 
 
The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and natural gas 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 oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas 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.
 
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 oil and natural gas 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 oil and natural gas 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 oil, natural gas and natural gas liquids 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 oil, natural gas and natural gas liquids. 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, or the “NGA”.  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.
 
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The ability to transport oil and natural gas liquids 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 just and reasonable rates published in agency-approved tariffs and require pipelines to provide non-discriminatory access and terms and conditions of service. The justness and reasonableness of interstate oil and natural gas liquid pipeline rates can be challenged at FERC through a protest or a complaint and, if such a protest or complaint results in a lower rate than that on file, pipeline shippers may be eligible to receive refunds or, in the case of a complaining shipper, reparations for the two-year period prior to the filing of the complaint. 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 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 and the Natural Gas Policy Act 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 discussed below 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.

In 2007, FERC issued a final rule on the annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing (“Order 704”). Under Order 704, wholesale buyers and sellers of more than 2.2 million MMBtu of physical natural gas in the previous calendar year, including interstate and intrastate natural gas pipelines, natural gas gatherers, natural gas processors and natural gas marketers are now required to report on Form No. 552, on May 1 of each year, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to, or may contribute to the formation of price indices. It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance of Order 704. Pursuant to Order 704, we may be required to annually report to FERC, starting May 1 information regarding natural gas purchase and sale transactions depending on the volume of natural gas transacted during the prior calendar year.

On August 6, 2009, the Federal Trade Commission, or “FTC”, issued a Final Rule prohibiting manipulative and deceptive conduct in the wholesale petroleum markets. The Final Rule applies to transactions in crude oil, gasoline, and petroleum distillates. The FTC promulgated the Final Rule pursuant to Section 811 of the Energy Independence and Security Act of 2007 (“EISA”), which makes it unlawful for anyone, in connection with the wholesale purchase or sale of crude oil, gasoline, or petroleum distillates, to use any “manipulative or deceptive device or contrivance, in contravention of such rules and regulations as the Federal Trade Commission may prescribe.” The Final Rule prohibits any person, directly or indirectly, in connection with the purchase or sale of crude oil, gasoline, or petroleum distillates at wholesale, from: a) knowingly engaging in any act, practice, or course of business – including making any untrue statement of material fact that operates or would operate as a fraud or deceit upon any person; or b) intentionally failing to state a material fact that under the circumstances renders a statement made by such person misleading, provided that such omission distorts or is likely to distort market conditions for any such product.

Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, FERC and the courts. We cannot predict the ultimate impact of these or the above regulatory changes to our natural gas operations. We do not believe that we would be affected by any such FERC action materially differently than other natural gas companies with whom we compete.
 
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The price at which we buy and sell natural gas is currently not subject to federal rate regulation and, for the most part, is not subject to state regulation. Sales of condensate and natural gas liquids are not currently regulated and are made at market prices. However, with regard to our physical purchases and sales of these energy commodities, and any related hedging activities that we undertake, we are required to observe anti-market manipulation laws and related regulations enforced by FERC and/or the Commodity Futures Trading Commission, or “CFTC”. Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third party damage claims by, among others, market participants, sellers, royalty owners and taxing authorities. 

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.
 
State Regulation.  The various states regulate the drilling for, and the production, gathering and sale of, oil, natural gas and natural gas liquids, including imposing severance and other production related taxes and requirements for obtaining drilling permits. Reduced rates or credits may apply to certain types of wells and production methods. For example, currently, a severance tax on oil, natural gas and natural gas liquids 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 oil and natural gas 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 oil, natural gas and natural gas liquids 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.

 In addition to production taxes, Texas and Montana each impose ad valorem taxes on oil and natural gas properties and production equipment. Wyoming and New Mexico impose an ad valorem tax on the gross value of oil and natural gas production in lieu of an ad valorem tax on the underlying oil and natural gas properties. Wyoming also imposes an ad valorem tax on production equipment. North Dakota imposes an ad valorem tax on gross oil and natural gas production in lieu of an ad valorem tax on the underlying oil and gas leases or on production equipment used on oil and gas leases.

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.

Federal, State, or Native American Leases.  Our operations on federal, state, or Native American oil and natural gas leases are subject to numerous restrictions, including nondiscrimination statutes. Such operations must be conducted pursuant to certain on-site security regulations and other permits and authorizations issued by the Federal Bureau of Land Management, Minerals Management Service, and other agencies.

 
Operating Hazards and Insurance

The oil and natural gas business involves a variety of operating risks, including fires, explosions, blowouts, environmental hazards, and other potential events that can adversely affect our ability to conduct operations and cause us to incur substantial losses. Such losses could reduce or eliminate the funds available for exploration, exploitation, or leasehold acquisitions or result in loss of properties.

In accordance with industry practice, we maintain insurance against some, but not all, potential risks and losses. We do not carry business interruption insurance. We may not obtain insurance for certain risks if we believe the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable at a reasonable cost.  If a significant accident or other event occurs that is not fully covered by insurance, it could adversely affect us.

 
Employees
 
 
As of March 1, 2011, we had 83 full time employees. 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.
 
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Offices
 
 
Our principal executive office is located at 5847 San Felipe, Suite 3000, Houston, Texas 77057. Our main telephone number is (832) 327-2255.
 
 
Available Information
 
Our website address is www.vnrllc.com. We make our website content available for information purposes only. It should not be relied upon for investment purposes, nor is it incorporated by reference in this Form 10-K. We make available on this website under "Investor Relations-SEC Filings," free of charge, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports as soon as reasonably practicable after we electronically file those materials with, or furnish those materials to, the SEC. The SEC also maintains a website at www.sec.gov that contains reports, proxy statements and other information regarding SEC registrants, including us.
 
You may also find information related to our corporate governance, board committees and company code of business conduct and ethics on our website. Among the information you can find there is the following:
 
 
• Audit Committee Charter;

 
• Nominating and Corporate Governance Committee Charter;

 
• Compensation Committee Charter;

 
• Conflicts Committee Charter;

 
• Code of Business Conduct and Ethics; and

 
• Corporate Governance Guidelines.
 
 
 
 
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 oil, natural gas and natural gas liquids we produce;
 
 
·
the price at which we are able to sell our oil, natural gas and natural gas liquids production;
 
 
·
the level of our operating costs;
 
 
·
the level and success of VNR’s and ENP’s price risk management activities;
 
 
·
the level of our interest expense which depends on the amount of our indebtedness and the interest payable thereon; and
 
 
·
the level of our capital expenditures.
 
In addition, the actual amount of cash we will have available for distribution will depend on other factors, some of which are beyond our control, including:
 
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·
the performance of ENP and its subsidiaries and ENP’s ability to make cash distributions to us, which is dependent upon the results of operations, cash flows and financial condition of ENP;
 
 
·
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 distributions, in which event the market price of our common units may decline substantially.

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, borrowings under our reserve-based credit facility and other financing arrangements; 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 and other financing arrangements when they expire.

The cost of raising money in the debt and equity capital markets has increased while the availability of funds from those markets generally has diminished. 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 pursue growth opportunities.

Our financing arrangements have 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 oil, natural gas and natural gas liquids reserves, which will take into account the prevailing oil, natural gas and natural gas liquids 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.

A future decline in commodity prices could result in a redetermination lowering our borrowing base in the future and, in such case, we could be required to repay any indebtedness in 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.
 
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The lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under our financing arrangements. 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 oil and natural gas 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.

ENP’s revolving credit facility also contains operating and financial restrictions and covenants which limit the amounts that ENP can borrow to a borrowing base amount, determined by the lenders in their sole discretion. Outstanding borrowings in excess of the borrowing base are required to be repaid immediately, or are required to pledge other oil and gas properties as additional collateral.

Our estimates of proved reserves have been prepared under new SEC rules which went into effect for fiscal years ending on or after December 31, 2009, which may make comparisons to periods prior to December 31, 2009 difficult and could limit our ability to book additional proved undeveloped reserves in the future.

Our reserve report presents estimates of our proved reserves as of December 31, 2010, which have been prepared and presented under new SEC rules. These new rules are effective for fiscal years ending on or after December 31, 2009, and require SEC reporting companies to prepare their reserves estimates using revised reserve definitions and revised pricing based on the 12-month average price. The previous rules required that reserve estimates be calculated using last-day-of the-year pricing. The pricing that was used for estimates of VNR’s reserves as of December 31, 2010 was based on the 12-month average price of $4.38 per MMBtu for natural gas and $ 79.40 per barrel of crude oil, as compared to $3.87 per MMBtu for natural gas and $61.04 per Bbl for oil as of December 31, 2009. As a result of these changes, direct comparisons to our previously-reported reserves prior to December 31, 2009 may be more difficult. 

The new SEC rules also state that, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years of the date of booking. This new rule has limited and may continue to limit our potential to book additional proved undeveloped reserves as we pursue our drilling program. Moreover, we may be required to write down our proved undeveloped reserves if we do not drill on those reserves within the required five-year timeframe.

The SEC has reviewed our and other reporting company’s reserve estimates under the new rules and has released only limited interpretive guidance regarding reporting of reserve estimates under the new rules and may not issue further interpretive guidance on the new rules. Accordingly, while the estimates of our proved reserves at December 31, 2010 included in this report have been prepared based on what we and our independent reserve engineers believe to be reasonable interpretations of the new SEC rules,
those estimates could differ materially from any estimates we might prepare applying more specific SEC interpretive guidance.

Oil, natural gas and natural gas liquids prices are volatile.  A decline in oil, natural gas and natural gas liquids 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 oil and natural gas properties depend primarily upon the prices we receive for our oil, natural gas and natural gas liquids production and the prices prevailing from time to time for oil, natural gas and natural gas liquids. 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 volatility in oil, natural gas and natural gas liquids prices has impacted the value of our estimated proved reserves and, in turn, the market values used by our lenders to determine our borrowing base. 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.

Oil, natural gas and natural gas liquids 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 crude oil spot price per barrel for the period between January 1, 2010 and December 31, 2010 ranged from a high of $91.48 to a low of $64.78 and the NYMEX natural gas spot price per MMBtu for the period January 1, 2010 to December 31, 2010 ranged from a high of $6.01 to a low of $3.29. As of March 1, 2011, the crude oil spot price per barrel was $99.63 and the NYMEX natural gas spot price per MMBtu was $3.87. 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 oil, natural gas and natural gas liquids are subject to a variety of factors, including:
 
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·
the level of consumer demand for oil, natural gas and natural gas liquids;
 
·      the domestic and foreign supply of oil, natural gas and natural gas liquids;

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

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

 
·
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 oil, natural gas and natural gas liquids prices would not only reduce our revenue, but could reduce the amount of oil, natural gas and natural gas liquids that we can produce economically and, as a result, could have a material adverse effect on our financial condition, results of operations and reserves. 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 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 oil and natural gas 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.
 
Lower oil, natural gas and natural gas liquids 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 oil and natural gas properties. Under this method, we capitalize the cost to acquire, explore for, and develop oil and natural gas properties. Under full cost accounting rules, the net capitalized costs of proved oil and natural gas 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 oil and natural gas 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 could have a material adverse effect on our results of operations in the period incurred and would reduce our members’ equity.

The risk that we will be required to write down the carrying value of our oil and natural gas properties increases when oil and gas prices are low or volatile. In addition, accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties and goodwill if we experience substantial downward adjustments to our estimated proved reserves, or if estimated future operating or development costs increase. For example, oil, natural gas and natural gas liquids prices were very volatile throughout 2009. We recorded a non-cash ceiling test impairment of natural gas and oil properties for the year ended December 31, 2009 of $110.2 million. The impairment for the first quarter 2009 was $63.8 million as a result of a decline in natural gas prices at the measurement date, March 31, 2009. This impairment was calculated based on prices of $3.65 per MMBtu for natural gas and $49.64 per barrel of crude oil. The SEC’s Final Rule, “Modernization of Oil and Gas Reporting,” which became effective December 31, 2009, changed the price used to calculate oil and gas reserves to a 12-month average price rather than a year-end price. As a result of declines in natural gas and oil prices based upon the 12-month average price, we recorded an additional impairment of $46.4 million in the fourth quarter of 2009. This impairment was calculated using the 12-month average price for natural gas and oilof $3.87 per MMBtu for natural gas and $ 61.04 per barrel of crude oil. These and other factors could cause us to record write downs of our oil and natural gas properties and other assets in the future and incur additional charges against future earnings. Based on the 12-month average natural gas and oil prices through February 2011, we do not anticipate an impairment at March 31, 2011.
 
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Our acquisition activities will subject us to certain risks.
 
Since 2008, we have expanded our operations through acquisitions. Any acquisition involves potential risks, including, among other things: the validity of our assumptions about reserves, future production, revenues and costs, including synergies; an inability to integrate successfully the businesses we acquire; a decrease in our liquidity by using a significant portion of our available cash or borrowing capacity to finance acquisitions; a significant increase in our interest expense or financial leverage if we incur additional debt to finance acquisitions; the assumption of unknown liabilities, losses or costs for which we are not indemnified or for which our indemnity is inadequate; the diversion of management’s attention to other business concerns; an inability to hire, train or retain qualified personnel to manage and operate our growing business and assets; the incurrence of other significant charges, such as impairment of other intangible assets, asset devaluation or restructuring charges; unforeseen difficulties encountered in operating in new geographic areas; an increase in our costs or a decrease in our revenues associated with any potential royalty owner or landowner claims or disputes; and customer or key employee losses at the acquired businesses.
 
Our decision to acquire a property will depend in part on the evaluation of data obtained from production reports and engineering studies, geophysical and geological analyses and seismic and other information, the results of which are often inconclusive and subject to various interpretations. Also, our reviews of acquired properties are inherently incomplete because it generally is not feasible to perform an in-depth review of the individual properties involved in each acquisition. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit us to become sufficiently familiar with the properties to assess fully their deficiencies and potential. Inspections may not always be performed on every well, and environmental problems, such as ground water contamination, are not necessarily observable even when an inspection is undertaken.
 
If our acquisitions do not generate increases in available cash per unit, our ability to make cash distributions to our unitholders could materially decrease.

A portion of our assets are our partnership interests in ENP and, therefore, our cash flow is dependent upon the ability of ENP to make distributions in respect of those partnership interests.

A portion of our assets are our partnership interests in ENP. As a result, our cash flow depends on the performance of ENP and its’ subsidiaries and ENP’s ability to make cash distributions to us, which is dependent on the results of operations, cash flows and financial condition of ENP. The amount of cash that ENP can distribute to its partners, including us, each quarter depends upon the amount of cash it generates from its operations, which will fluctuate from quarter to quarter and will depend on, among other things:

 
·
the price of oil and natural gas;
 
 
·
the weather in ENP’s operating areas;
 
 
·
the level of competition from other oil and natural gas companies;
 
 
·
the level of ENP’s operating costs;
 
 
·
prevailing economic conditions; and
 
 
·
the level and success of ENP’s price risk management activities.
 
In addition, the actual amount of cash that ENP will have available for distribution will also depend on other factors, such as:

 
·
the level of capital expenditures it makes;
 
 
·
its ability to make borrowings under its revolving credit facility to pay distributions;
 
 
·
its cost of acquisitions and sources of cash used to fund its acquisitions;
 
 
·
debt service requirements and restrictions on distributions contained in its revolving credit facility or future debt agreements;
 
 
·
fluctuations in its working capital needs;
 
 
·
its general and administrative expenses;
 
 
·
its cash settlements of commodity derivative contracts;
 
 
·
the timing and collectability of its receivables; and
 
 
·
the amount of cash reserves established by the board of directors of ENP’s general partner for the proper conduct of its business.
 
 
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We do not have complete control over many of these factors. Accordingly, we cannot guarantee that ENP will have sufficient available cash to pay a specific level of cash distributions to its partners.

Furthermore, unitholders should be aware that the amount of cash that ENP has available for distribution depends primarily upon cash flow, including cash flow from financial reserves and working capital borrowings, and is not solely a function of profitability, which will be affected by non-cash items. As a result, ENP may make cash distributions during periods when it records net losses and may not make cash distributions during periods when it records net income.

The consolidated debt level and debt agreements of ENP and its subsidiaries may limit the distributions we receive from ENP and our future financial and operating flexibility.

As of December 31, 2010, ENP had approximately $234.0 million of outstanding borrowings and $141.0 million of capacity under its revolving credit facility. ENP’s level of indebtedness affects its operations in several ways, including, among other things:

 
·
ENP’s ability to obtain additional financing, if necessary, for working capital, capital expenditures;
 
 
·
acquisitions, or other purposes may not be available on favorable terms, if at all;
 
 
·
covenants contained in future debt arrangements may require ENP to meet financial tests that may affect its flexibility in planning for and reacting to changes in its business, including possible acquisition opportunities;
 
 
·
ENP will need a substantial portion of its cash flow to make principal and interest payments on its indebtedness, reducing the funds that would otherwise be available for operations, future business opportunities, and distributions to unitholders; and
 
 
·
ENP’s debt level will make it more vulnerable to competitive pressures, or a downturn in our business or the economy in general, than its competitors with less debt.
 
ENP is not prohibited from competing with us.

Neither our partnership agreement nor the partnership agreement of ENP prohibit ENP from owning assets or engaging in businesses that compete directly or indirectly with us. In addition, ENP may acquire, construct or dispose of any assets in the future without any obligation to offer us the opportunity to purchase or construct any of those assets.

ENP may issue additional common units, which may increase the risk that ENP will not have sufficient available cash to maintain or increase its per unit distribution level.

The partnership agreement of ENP allows ENP to issue an unlimited number of additional limited partner interests. The issuance of additional common units or other equity securities by ENP will have the following effects:

 
·
unitholders’ current proportionate ownership interest in ENP will decrease;
 
 
·
the amount of cash available for distribution on each common unit or partnership security may decrease;
 
 
·
the ratio of taxable income to distributions may increase;
 
 
·
the relative voting strength of each previously outstanding common unit may be diminished; and
 
 
·
the market price of ENP’s common units may decline.
 
 
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The payment of distributions on any additional units issued by ENP may increase the risk that ENP may not have sufficient cash available to maintain or increase its per unit distribution level, which in turn may impact the available cash that we have to meet our obligations.

We rely on Vinland, an affiliate of our founding 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 founding unitholder, under which we rely on Vinland to operate all of our existing producing wells and coordinate our development drilling program in Appalachia. Under the agreements, Vinland will also advise and consult with us regarding all aspects of our production and development operations in Appalachia and provide us with administrative support services as necessary or useful for the operation of our business. If Vinland fails to or inadequately performs these functions, our operations in Appalachia will be disrupted and our costs could increase or our reserves may not be developed or properly developed, reducing our future levels of production and our cash from operations, which could affect our ability to make cash distributions to our unitholders.
 
We could lose our interests in future wells if we fail to participate under our operating agreement with Lewis Petroleum in the drilling of these wells.
 
Under the terms of our operating agreement with Lewis Petroleum, 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.

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 r