10-K 1 form10-k.htm FORM 10-K form10-k.htm



UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
FORM 10-K
     
(Mark One)
 
 
x
 
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
     
   
For the fiscal year ended December 31, 2011
 
   
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 x
 
No o
 
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 x
 
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, 2011 was approximately $675,664,323 based upon the New York Stock Exchange composite transaction closing price.
 
As of March 1, 2012 53,469,703 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 2012 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, 2011 (“this Annual Report”).
 

 
 

 
 
Vanguard Natural Resources, LLC
 
TABLE OF CONTENTS
 
 
Caption
 
Page
     
 
   
     
   
     
   
     
   
 
 

 
 

 
 
Forward-Looking Statements
 
Certain statements and information in this Annual Report may constitute “forward-looking statements.”  The words “may,” “will,” estimate,” “predict,” “potential,” “believe,” “expect,” “anticipate,” “plan,” “intend,” “foresee,” “should,” “would,” “could” or other similar expressions are intended to identify forward-looking statements, which are generally not historical in nature.  These forward-looking statements are based on our current expectations and beliefs concerning future developments and their potential effect on us.  While management believes that these forward-looking statements are reasonable as and when made, there can be no assurance that future developments affecting us will be those that we anticipate.  All comments concerning our expectations for future revenues and operating results are based on our forecasts for our existing operations and do not include the potential impact of any future acquisitions.  Our forward-looking statements involve significant risks and uncertainties (some of which are beyond our control) and assumptions that could cause actual results to differ materially from our historical experience and our present expectations or projections.  Known material factors and other factors that could cause our actual results to differ from those in the forward-looking statements are those described in “Item 1A. Risk Factors” and those described elsewhere in this Annual Report.

Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof.  We undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events or otherwise.

 
 

 
 
 
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
 
MMBbls
= million barrels
         
BOE
= barrel of oil equivalent
 
MMBOE
= million barrels of oil equivalent
         
Btu
= British thermal unit
 
MMBtu
= million British thermal units
         
MBbls
= thousand barrels
 
MMcf
= million cubic feet
         
MBOE
= thousand barrels of oil equivalent
 
 NGLs
 = natural gas liquids
 
When we refer to oil, natural gas and NGLs in “equivalents,” we are doing so to compare quantities of oil and NGLs 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 NGLs and one Bbl of oil or one Bbl of NGLs 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) “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, increasing our quarterly cash distributions through the acquisition of additional mature, long-lived oil and natural gas properties. Through our operating subsidiaries, we own properties and oil and natural gas reserves primarily located in seven operating areas:

·  
the Permian Basin in West Texas and New Mexico;

·  
the Big Horn Basin in Wyoming and Montana;

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

·  
South Texas;

·  
the Williston Basin in North Dakota and Montana;

·  
Mississippi; and

·  
the Arkoma Basin in Arkansas and Oklahoma.
 
Our common units are listed on the New York Stock Exchange, or “NYSE,” under the symbol “VNR.”

 
Recent Developments

ENP Acquisition

On December 31, 2010, we acquired (the “ENP Purchase”) all of the member interests in ENP GP, the general partner of ENP, and  20,924,055 common units representing limited partnership interests in ENP (the “ENP Units”), together representing a 46.7% aggregate equity interest in ENP at the date of the ENP Purchase, from 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”). As consideration for the purchase, we paid $300.0 million in cash and issued 3,137,255 VNR common units, valued at $93.0 million at December 31, 2010.

On December 1, 2011, we acquired the remaining 53.4% of the ENP Units not held by us through a merger (the “ENP Merger”) with one of our wholly owned subsidiaries. In connection with the ENP Merger, ENP’s public unitholders received 0.75 Vanguard common units in exchange for each ENP common unit they owned at the effective date of the ENP Merger, which resulted in the issuance of approximately 18.4 million VNR common units valued at $511.4 million at December 1, 2011. We refer to the ENP Purchase and ENP Merger collectively as the “ENP Acquisition.” ENP’s properties are located in Wyoming, Montana, West Texas, New Mexico, North Dakota, Arkansas and Oklahoma. As of December 31, 2011, based on a reserve report prepared by our independent reserve engineers, DeGolyer & MacNaughton, the acquired properties from the ENP Acquisition had estimated proved reserves of 44.0 MMBOE, of which 71% was oil and 88% was proved developed producing.

Other Acquisitions

Newfield Acquisition

On April 28, 2011, we entered into a Purchase and Sale Agreement with a private seller, for the acquisition of certain oil and natural gas properties located in Texas and New Mexico. We refer to this acquisition as the “Newfield Acquisition.”  The purchase price for the assets was $9.1 million with an effective date of April 1, 2011. We completed this acquisition on May 12, 2011 for an adjusted purchase price of $9.2 million. This acquisition was funded with borrowings under financing arrangements existing at that time. As of December 31, 2011, based on a reserve report prepared by our independent reserve engineers, these acquired properties had estimated proved reserves of 0.3 MMBOE, of which 85% was oil and 100% was proved developed producing.

 
1

 
Permian Basin Acquisition I

On June 22, 2011, pursuant to two Purchase and Sale Agreements, we and ENP agreed to acquire producing oil and natural gas assets in the Permian Basin in West Texas (the “Purchased Assets”) from a private seller. We refer to this acquisition as the “Permian Basin Acquisition I.” We and ENP agreed to purchase 50% of the Purchased Assets for an aggregate of $85.0 million and each paid the seller a non-refundable deposit of $4.25 million. The effective date of this acquisition was May 1, 2011. This acquisition was completed on July 29, 2011 for an aggregate adjusted purchase price of $81.4 million.  The purchase price was funded with borrowings under financing arrangements existing at that time. As of December 31, 2011, based on a reserve report prepared by our independent reserve engineers, the interests acquired had estimated total net proved reserves of 4.0 MMBOE, of which 69% was oil and NGLs reserves and are 100% was proved developed.

Permian Basin Acquisition II

On August 8, 2011, ENP entered into assignment agreements and completed the acquisition of certain oil and natural gas properties located in the Permian Basin of West Texas from a private seller. We refer to this acquisition as the “Permian Basin Acquisition II.” The adjusted purchase price for the assets was $14.8 million with an effective date of May 1, 2011. This acquisition was funded with borrowings under financing arrangements existing at that time. As of December 31, 2011, based on a reserve report prepared by our independent reserve engineers, the interests acquired had estimated total net proved reserves of 1.2 MMBOE, of which 89% was oil and are 57% was proved developed.

Wyoming Acquisition

On August 15, 2011, ENP entered into a definitive agreement with a private seller for the acquisition of certain oil and natural gas properties located in Wyoming. We refer to this acquisition as the “Wyoming Acquisition.” The purchase price for the assets was $28.5 million with an effective date of June 1, 2011. ENP completed this acquisition on September 1, 2011 for an adjusted purchase price of $27.7 million. The purchase price was funded with borrowings under financing arrangements existing at that time. As of December 31, 2011, based on a reserve report prepared by our independent reserve engineers, the interests acquired had estimated total net proved reserves of 2.9 MMBOE, of which 94% was natural gas reserves and 100% was proved developed.

Gulf Coast Acquisition

On August 31, 2011, ENP entered into a definitive agreement and completed the acquisition of certain non-operated working interests in mature producing oil and natural gas properties located in the Texas and Louisiana onshore Gulf Coast area from a private seller. We refer to this acquisition as the “Gulf Coast Acquisition.” The adjusted purchase price for the assets was $47.6 million with an effective date of August 1, 2011. This acquisition was funded with borrowings under financing arrangements existing at that time. As of December 31, 2011, based on a reserve report prepared by our independent reserve engineers, the interests acquired had estimated total net proved reserves of 2.2 MMBOE, of which 81% was oil and NGLs reserves and 100% was proved developed.

North Dakota Acquisition

On December 1, 2011, we entered into a definitive agreement and completed the acquisition of certain non-operated working interests in mature producing oil and natural gas properties located in the North Dakota from a private seller. We refer to this acquisition as the “North Dakota Acquisition.” The adjusted purchase price for the assets was $7.6 million with an effective date of September 1, 2011. This acquisition was funded with borrowings under financing arrangements existing at that time. As of December 31, 2011, based on a reserve report prepared by our independent reserve engineers, the interests acquired had estimated total net proved reserves of 0.5 MMBOE, of which 96% was oil and 100% was proved developed.

Parker Creek Acquisition

During 2010, we completed an 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.” On December 12, 2011, we acquired additional working interest in the same oil properties acquired in the Parker Creek Acquisition located in Mississippi.  We completed this acquisition on December 22, 2011 for a purchase price of $14.4 million.  The effective date of this acquisition was December 1, 2011. The acquisition of additional working interest was funded with borrowings under financing arrangements existing at that time.  As of December 31, 2011, based on a reserve report prepared by our independent reserve engineers, these properties acquired in 2010 and 2011 had estimated proved reserves of 2.6 MMBOE, of which 96% was oil and 58% was proved developed producing.

 
2

 
Credit Facilities

On September 30, 2011 we entered into the Third Amended and Restated Credit Agreement (the “Credit Agreement”) with a maximum facility amount of $1.5 billion (the “reserve-based credit facility”). This Credit Agreement, which was effective December 1, 2011, provides for an initial borrowing base of $765.0 million and a maturity date of October 31, 2016.  As a result of this amendment, our interest rates are lower and several key covenant limitations were amended, including increasing the percentage of production that can be hedged into the future which provides us greater flexibility. Our obligations under the reserve-based credit facility are secured by mortgages on our oil and natural gas properties and other assets and are guaranteed by all of our operating subsidiaries. As of March 1, 2012 we had $581.0 million in borrowings outstanding under the reserve-based credit facility.

On November 30, 2011, we also entered into a $100.0 million senior secured second lien term loan facility (the “Second Lien Term Loan”). The loans under the Second Lien Term Loan mature on May 30, 2017 and accrue interest at an interest rate per annum equal to the London interbank offered rate, or LIBOR, plus 5.5%. In January 2012, we repaid $43.0 million of our borrowings under the Second Lien Term Loan. As of March 1, 2012 we had $57.0 million in borrowings outstanding under the Second Lien Term Loan.

Borrowings under each of the reserve-based credit facility and the Second Lien Term Loan were used to repay loans outstanding under ENP’s senior secured revolving credit facility (the “ENP Credit Agreement”) and our $175.0 million term loan (the “Term Loan”.) Please see “Item 7. Management’s Discussion and Analysis and Results of Operations—Capital Resources and Liquidity—Debt and Credit Facilities” for additional information regarding our credit facilities.

Organizational Structure

The following diagram depicts our organizational structure as of March 5, 2012:
 
 

 
 
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, 2011 were 79.3 MMBOE, of which approximately 57% were oil reserves, 34% were natural gas reserves and 9% were NGLs reserves.  Of these total estimated proved reserves, approximately 86% were classified as proved developed. At December 31, 2011, we owned working interests in 4,900 gross (2,245 net) productive wells. Our operated wells accounted for approximately 62% of our total estimated proved reserves at December 31, 2011.Our average net daily production for the year ended December 31, 2011 was 13,405 BOE/day. Our average net production for the year ended December 31, 2011 includes production from the properties acquired in connection with the ENP Acquisition. Production from these properties during 2011 through the date of the completion of the ENP Merger on December 1, 2011 was subject to a 53.4% non-controlling interest in ENP. In the Permian Basin, Big Horn Basin, South Texas and Williston Basin, we own working interests ranging from 30-100% in approximately 42,468 gross undeveloped acres surrounding our existing wells.

Our average proved reserves-to-production ratio, or average reserve life, is approximately 16 years based on our total proved reserves as of December 31, 2011 and the combined production of VNR and ENP for 2011. As of December 31, 2011, we have identified 442 proved undeveloped drilling locations and over 205 other drilling locations on our leasehold acreage.

In February 2012, we entered into a Unit Exchange Agreement with our founding unitholder to transfer our ownership interests in oil and natural gas properties in the Appalachian Basin in exchange for 1.9 million VNR common units with an effective date of January 1, 2012. As of December 31, 2011, based on a reserve report prepared by our independent reserve engineers, these interests had estimated total net proved reserves of 6.2 MMBOE, of which 92% was natural gas and 65% was proved developed. This transaction is expected to close in March 2012.

 
Business Strategies
 
 
Our primary business objective is to generate 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 hedging strategy to reduce the volatility in our revenues resulting from changes in oil, natural gas and NGLs prices.

 
Properties
 
As of December 31, 2011, through certain of our subsidiaries, we own interests in oil and gas properties located in the Permian Basin, the Big Horn Basin, the Appalachian Basin, South Texas, the Williston Basin, Mississippi and the the Arkoma Basins. The following table presents the production for the year ended December 31, 2011 and the estimated proved reserves for each operating area:
 
           
Net
 
           
Estimated
 
     
2011 Net
   
Proved
 
 
Operator
 
Production
   
Reserves
 
     
(MBOE)
   
(MBOE)
 
  Permian Basin
Vanguard Permian, LLC
   
586
     
10,056
 
  Permian Basin
Encore Energy Partners Operating LLC
   
1,261
(1)
   
19,847
 
  Big Horn Basin
                 
     Elk Basin
Encore Energy Partners Operating LLC
   
905
(1)
   
17,684
 
     Others
Encore Energy Partners Operating LLC
   
522
(1)
   
8,797
 
  Appalachian Basin (2)
Vinland Energy Operations, LLC
   
533
     
6,171
 
  South Texas
Lewis Petroleum
   
393
     
7,844
 
  Williston Basin
Encore Energy Partners Operating LLC
   
344
(1)
   
5,353
 
  Mississippi
Vanguard Permian, LLC
   
218
     
2,487
 
  Arkoma Basin
Encore Energy Partners Operating LLC
   
133
(1)
   
1,086
 
 

(1)
 
Production from the properties acquired in connection with the ENP Purchase during 2011 through the date of the completion of the ENP Merger on December 1, 2011 was subject to a 53.4% non-controlling interest in ENP. 
(2)
 
In February 2012, we entered into a Unit Exchange Agreement to transfer our ownership interests in these properties. See “Subsequent Events” in the Notes to the Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” of this Annual Report.

 
4

 
The following is a description of our properties by operating area:

Permian Basin Properties

The Permian Basin is one of the largest and most prolific oil and natural gas producing basins in the United States extending over West Texas and southeast New Mexico. The Permian Basin is characterized by oil and natural gas fields with long production histories and multiple producing formations.  Our properties classified as Permian Basin properties also include properties we acquired on August 31, 2011 in the onshore Gulf Coast area where most of the production comes from the Silsbee Field in Hardin County, Texas.  The Silsbee Field is operated by Silver Oak Energy. Most of the Silsbee production is oil produced from the Yegua formation.

During 2011, our Permian Basin operations produced approximately 1,847 MBOE, of which 57% was oil, condensate and NGLs. These properties accounted for approximately 29,903 MBOE or 38% of our total estimated proved reserves at year end, of which 25,616 MBOE were proved developed and 4,287 MBOE were proved undeveloped. Our average working interest in these properties is approximately 79%. As of December 31, 2011, our Permian Basin properties consisted of 121,952 gross (91,564 net) acres.

Big Horn Basin Properties

The Big Horn Basin is a prolific basin which is characterized by oil and natural gas fields with long production histories and multiple producing formations.

Our Big Horn Basin properties are comprised of assets in Wyoming, including the Gooseberry field, and the Elk Basin field in south central Montana. We own working interests ranging from 61% to 100% in our Big Horn Basin properties, which consisted of 36,312 gross (31,651 net) acres as of December 31, 2011. During 2011, our properties in the Big Horn Basin produced approximately 1,427 MBOE, of which 80% was oil.  The Big Horn Basin properties accounted for approximately 26,480 MBOE or 33% of our total estimated proved reserves at year end, of which 25,575 MBOE were proved developed and 905 MBOE were proved undeveloped.

Our Elk Basin field is located in Park County, Wyoming and Carbon County, Montana.  We operate all properties in the Elk Basin area which includes the Embar-Tensleep, Madison and Frontier 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. Our wells in the Embar-Tensleep formation of the Elk Basin field are drilled to a depth of 4,200 to 5,400 feet.

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.

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.

The Gooseberry field is located in Park County and Hot Springs, Wyoming and 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.

Most of the production from our Big Horn Basin properties in southwest Wyoming comes from the Hay Reservoir Field located in Sweetwater County, Wyoming.  Most of the Hay Reservoir production is high BTU gas produced from the Lewis formation.

We operate and own 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 (“Exxon”) 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 Elk Basin fields.

 
5

 
We own and operate the Wildhorse pipeline system, which is an approximately 12-mile natural gas gathering system that transports approximately 1.0 MMcf/day of low-sulfur natural gas from the South Elk Basin fields to the Elk Basin natural gas processing plant.

Appalachian Basin Properties

Our properties in Appalachia are operated by Vinland and are located in southeastern Kentucky and northeastern Tennessee. Our working interest ranges from 40% to 100% for most of the approximate 922 wells. Most of the production is high BTU gas that produces primarily from the Maxon, Big Lime and Devonian Shales from a depth ranging from approximately 1,500 feet to 4,500 feet.

During 2011, the properties in Appalachia produced approximately 533 MBOE, of which 83% was natural gas. These properties accounted for approximately 6,171 MBOE or 8% of our total estimated proved reserves at year end, of which 4,020 MBOE were proved developed and 2,151 MBOE were proved undeveloped. As of December 31, 2011, our Appalachian Basin properties consisted of 130,191 gross (65,559 net) acres.

In February 2012, we entered into a Unit Exchange Agreement with our founding unitholder to transfer our ownership interests in oil and natural gas properties in the Appalachian Basin in exchange for 1.9 million VNR common units with an effective date of January 1, 2012.

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, respectively. 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 2011, the South Texas properties produced approximately 393 MBOE, of which 61% was natural gas. These properties accounted for approximately 7,844 MBOE or 10% of our total estimated proved reserves at year end, of which 5,112 MBOE were proved developed and 2,733 MBOE were proved undeveloped. As of December 31, 2011, our South Texas properties consisted of 21,020 gross (14,267 net) acres.

Williston Basin Properties

Our 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. During 2011, the properties produced approximately 344 MBOE, of which 90% was oil. Our Williston Basin properties had estimated proved reserves at December 31, 2011 of 5,353 MBOE or 7% of our total estimated proved reserves at year end, of which 92% was oil and 91% of which was proved developed.

Mississippi Properties

Most of our Mississippi properties, which we operate, are located in the Mississippi Salt Basin. The majority of our production comes from the Parker Creek Field in Jones County, Mississippi, where our working interest is approximately 65%. We also have a license for 10 square miles of 3-D seismic data for the development of Parker Creek Field. Our production is mainly oil that produces from the Hosston Formation from a depth ranging from approximately 13,000 feet to 15,000 feet.

During 2011, the Mississippi properties produced approximately 218 MBOE, of which 99% was oil.  These properties accounted for approximately 2,487 MBOE or 3% of our total estimated proved reserves at year end, of which 1,894 MBOE were proved developed and 593 MBOE were proved undeveloped. As of December 31, 2011, our Mississippi properties consisted of 2,560 gross (1,296 net) acres.

Arkoma Basin Properties

Our Arkoma Basin 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. During 2011, the properties produced approximately 133 MBOE, of which 85% was natural gas. At December 31, 2011, the properties had total proved reserves of approximately 1,086 MBOE or 1% of our total estimated proved reserves at year end, all of which were proved developed and 73% of which were natural gas.
 
 
6

 
 
Oil, Natural Gas and NGLs Prices
 
 
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 NGLs resulting from such processing, depending on the terms of the various agreements. For the year ended December 31, 2011, the average premium over New York Mercantile Exchange, or “NYMEX,” from the sale of casinghead gas plus our share of the revenues from the sale of NGLs was $1.30 per Mcfe.

The marketing of heavy sour crude oil production from our Big Horn Basin properties is done through our Clearfork pipeline, which transports the crude oil to local and other refiners through connections to other interstate pipelines.  Our Big Horn Basin 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. During 2011, we received the average NYMEX price less $14.42 per barrel in the Big Horn Basin and the average NYMEX price less $9.57 per barrel in the Williston Basin.

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. Specifically, 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 NYMEX natural gas prices due to the proximity to major consuming markets in the northeastern United States. For the year ended December 31, 2011, 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 $0.11 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, 2011, our average realized natural gas prices in Appalachia (before hedging), represented a $0.64 per Mcfe premium to NYMEX natural gas prices, which accounts for both the basis differential and the Btu adjustments.
 
 Our oil production 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. We sell oil production from our operated Permian Basin properties at the wellhead to third party gathering and marketing companies. During 2011, we received the average West Texas Intermediate, or “WTI,” price less $11.67 per barrel in Appalachia and the average WTI price less $3.55 per barrel in the Permian Basin.

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 our South Texas properties, an affiliate of Lewis Petroleum, 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 NGLs associated with the processing of such gas, our revenues on an Mcf basis are a premium to the NYMEX prices. For the year ended December 31, 2011, the average premium over NYMEX from the sale of natural gas plus our share of the revenues from the sale of NGLs was $2.17 per Mcfe.

The difference between NYMEX market prices and the price received at the wellhead for oil and natural gas production is commonly referred to as a differential.  In recent years, production increases from competing Canadian and Rocky Mountain producers, in conjunction with limited refining and pipeline capacity from the Rocky Mountain area, have affected this differential.  We cannot always accurately predict future crude oil and natural gas differentials.  

Certain of our natural gas marketing contracts determine the price that we are paid based on the value of the dry gas sold plus a portion of the value of NGLs extracted.  Since title of the natural gas sold under these contracts passes at the inlet of the processing plant, we report inlet volumes of natural gas in Mcf as production.  As a result of the incremental NGLs value and the improved differential, the price we were paid per Mcf for natural gas sold under certain contracts during 2011 increased to a level above NYMEX.
 
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, basis swaps, swaptions, put options, NYMEX collars and three-way 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.”
 
 
7

 
 
Oil, Natural Gas and NGLs Data

 
Estimated Proved Reserves
 
The following table presents our estimated net proved oil, natural gas and NGLs reserves and the present value of the estimated proved reserves at December 31, 2011, based on reserve reports prepared by D&M. Copies of their summary reports are included as exhibits to this Annual Report. 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 NGLs reserves.
 
Reserve Data:
     
Estimated net proved reserves:
     
Crude oil (MBbls)
    44,803  
Natural gas (Bcf)
    163  
NGLs (MBbls)
    7,385  
Total (MMBOE)
    79.3  
Proved developed (MMBOE)
    68.2  
Proved undeveloped (MMBOE)
    11.1  
Proved developed reserves as % of total proved reserves
    86 %
Standardized Measure (in millions) (1)(2)
  $ 1,476.2  
Representative Oil and Natural Gas Prices (3):
       
Oil—WTI per Bbl
  $ 96.24  
Natural gas—Henry Hub per MMBtu
  $ 4.12  
 
 
(1)   Does not give effect to hedging transactions. For a description of our hedging transactions, please read “Item 7A—Quantitative and Qualitative Disclosures About Market Risk.”

 
(2)   For an explanation of Standardized Measure, please see “Supplemental Oil and Natural Gas Information” in the Notes to the Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” of this Annual Report.
 
 
(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 2011, with these representative prices adjusted by field for quality, transportation fees and regional price differentials to arrive at the appropriate net price.
 
The following tables set forth certain information with respect to our estimated proved reserves by operating area as of December 31, 2011 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
                 
Permian Basin
64.9
12.1
2.7
25.6
8.5
2.7
0.2
4.3
29.9
Big Horn Basin
20.0
20.8
1.5
25.6
0.9
0.9
26.5
Appalachian Basin (1)
21.2
0.5
4.0
12.9
2.1
6.1
South Texas
18.0
0.1
2.0
5.1
9.8
0.1
1.0
2.7
7.8
Williston Basin
2.5
4.4
4.9
0.2
0.5
0.5
5.4
Mississippi
0.1
1.9
1.9
0.6
0.6
2.5
Arkoma Basin
4.8
0.3
1.1
1.1
Total
131.5
40.1
6.2
68.2
31.4
4.8
1.2
11.1
79.3
 
(1)
In February 2012, we entered into a Unit Exchange Agreement to transfer our ownership interests in these properties. See “Subsequent Events” in the Notes to the Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” of this Annual Report.
 

 
8

 

                         
   
PV10 Value (1)
 
Operating Area
 
Developed
   
Undeveloped
   
Total
 
   
(in millions)
 
  Permian Basin
 
$
471.9
   
$
71.8
   
$
543.7
 
  Big Horn Basin
   
558.5
     
20.3
     
578.8
 
  Appalachian Basin (2)
   
46.7
     
(5.8
   
40.9
 
  South Texas
   
59.9
     
18.3
     
78.2
 
  Williston Basin
   
115.1
     
6.7
     
121.8
 
  Mississippi
   
71.4
     
23.8
     
95.2
 
  Arkoma Basin
   
17.6
     
     
17.6
 
                         
Total
 
$
1,341.1
   
$
135.1
   
$
1,476.2
 
                         
 
 
     
(1)
 
PV10 is not a measure of financial or operating performance under generally accepted accounting principles, or “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 included in “Item 8. Financial Statements and Supplementary Data” of this Annual Report.
 
     
(2)
 
In February 2012, we entered into a Unit Exchange Agreement to transfer our ownership interests in these properties. See “Subsequent Events” in the Notes to the Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” of this Annual Report.

The data in the above tables represent estimates only. Oil, natural gas and NGLs reserve engineering is inherently a subjective process of estimating underground accumulations of oil, natural gas and NGLs 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 NGLs 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 unweighted arithmetic average first day of the month prices for the 12-month period ended December 31, 2011 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 2011, we paid D&M approximately $53,000 for all reserve and economic evaluations.

Proved Undeveloped Reserves

Our proved undeveloped reserves at December 31, 2011, as estimated by our independent petroleum engineers, were 11.1 MMBOE, consisting of 4.8 million barrels of oil, 31.4 MMcf of natural gas and 1.2 million barrels of NGLs. Our proved undeveloped reserves decreased by 2.5 MMBOE during the year ended December 31, 2011, as compared to the year ended December 31, 2010, resulting from the development of 13% of our total proved undeveloped reserves booked as of December 31, 2010 through the drilling of nine gross (6.9 net) wells at an aggregate capital cost of approximately $13.5 million, offset by the additions of proved undeveloped reserves through acquisitions made in 2011.  

 
9

 
At December 31, 2011, we have proved undeveloped properties that are scheduled to be drilled on a date more than five years from the date the reserves were initially booked as proved undeveloped and therefore the reserves from these properties are not included in our year end reserve report prepared by our independent reserve engineers. These properties include nine locations with 0.4 MMBOE of proved undeveloped reserves in the Permian Basin, two locations with 0.2 MMBOE of proved undeveloped reserves in the Big Horn Basin, 33 locations with 0.3 MMBOE of proved undeveloped reserves in the Appalachian Basin and 50 locations with 1.7 MMBOE of proved undeveloped reserves in the South Texas area. None of our proved undeveloped reserves at December 31, 2011 have remained undeveloped for more than five years since the date of initial booking as proved undeveloped reserves.

At December 31, 2011, all of our leases were held by production.

Qualifications of Technical Persons and Internal Controls over Reserves Estimation Process

Our proved reserve information as of December 31, 2011 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 28 years of experience and graduated from Texas A&M University with a Bachelor of Science degree in Petroleum Engineering in 1983. 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 36 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 holds 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 oil and gas reserves are the estimated quantities of crude oil, natural gas, and NGLs which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. 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.

 
Production and Price History
 
 
The following table sets forth information regarding net production of oil, natural gas and NGLs and certain price and cost information for each of the periods indicated.

 
10

 
 
   
Net Production
Average Realized Sales Prices (4)
Production Cost (5)
   
Crude Oil
Bbls/day
Natural Gas
Mcf/day
NGLs
Bbls/day
Crude Oil
Per Bbl
Natural Gas
Per Mcf
NGLs
Per Bbl
Per BOE
Year Ended December 31, 2011 (1)(6)
               
Elk Basin Field
 
2,098
315
328
$
81.02
$
3.38
$
84.90
$
10.99
Other
 
5,370
28,214
855
$
83.02
$
7.50
$
59.96
$
13.54
Total
 
7,468
28,529
1,183
$
82.45
$
7.45
$
66.88
$
13.07
                 
Year Ended December 31, 2010 (2)
               
Sun TSH Field
 
40
2,586
358
$
75.74
$
7.59
$
47.88
$
5.77
Other
 
1,830
11,086
216
$
76.54
$
10.45
$
41.58
$
11.77
Total
 
1,870
13,672
574
$
76.53
$
9.91
$
45.78
$
10.72
                         
Year Ended December 31, 2009 (3)
                       
Sun TSH Field
 
26
1,124
169
$
65.40
$
11.03
$
39.90
$
3.76
Other
 
921
11,320
146
$
75.54
$
11.16
$
31.50
$
11.25
Total
 
947
12,444
315
$
75.26
$
11.15
$
36.12
$
10.39


(1)  
Average daily production for 2011 calculated based on 365 days including production for all of our and ENP’s acquisitions from the closing dates of the acquisitions.

(2)  
Average daily production for 2010 calculated based on 365 days including production for the Parker Creek Acquisition from the closing date of this acquisition.

(3)        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.

(4)        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.

(5)
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).

(6)
Production from the properties acquired related to the ENP Purchase during 2011 through the date of the completion of the ENP Merger on December 1, 2011 was subject to a 53.4% non-controlling interest in ENP. 

 
Productive Wells
 
 
The following table sets forth information at December 31, 2011 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
 
  Permian Basin
    582       282       2,391       564       2,973       846  
  Big Horn Basin
    85       45       305       251       390       296  
  Appalachian Basin (1)
    869       759       53       44       922       803  
  South Texas
    198       194       12       12       210       206  
  Williston Basin
    90       7       162       67       252       74  
  Mississippi
    3             17       9       20       9  
  Arkoma Basin
    131       11       2             133       11  
Total
    1,958       1,298       2,942       947       4,900       2,245  
 
 
(1)
 
 In February 2012, we entered into a Unit Exchange Agreement to transfer our ownership interests in these properties. See “Subsequent Events” in the Notes to the Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” of this Annual Report.


 
11

 
 
Developed and Undeveloped Acreage
 
 
The following table sets forth information as of December 31, 2011 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)
 
  Permian Basin
    112,707       84,634       9,245       6,930       121,952       91,564  
  Big Horn Basin
    35,192       30,578       1,120       1,073       36,312       31,651  
  Appalachian Basin (5)
    20,900       18,966       109,291       46,593       130,191       65,559  
  South Texas
    8,480       8,262       12,540       6,004       21,020       14,266  
  Williston Basin
    44,790       35,548       19,206       9,474       63,996       45,022  
  Mississippi
    2,560       1,296                   2,560       1,296  
  Arkoma Basin
    3,192       411       357       84       3,549       495  
Total
    227,821       179,695       151,759       70,158       379,580       249,853  
 
 
(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)        In February 2012, we entered into a Unit Exchange Agreement to transfer our ownership interests in these properties. See “Subsequent Events” in the Notes to the Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” of this Annual Report.
 
 
 
Drilling Activity

In the Permian Basin, we drilled one Vanguard-operated horizontal oil well during 2011 in the Bone Spring sand in Ward County, Texas. This well was drilled to a vertical depth of approximately 11,300 feet with an approximate 4,500 feet lateral and completed with a nine stage fracture stimulation job. There were four proved undeveloped horizontal Bone Spring wells remaining to drill at year end 2011.

In the Big Horn Basin, during 2011 we drilled three productive vertical Madison oil wells in the Elk Basin field with approximately 62.2% working interest. 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.  During 2011, we drilled three oil wells in this area.

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 2011, we drilled three vertical Olmos and Escondido gas wells in La Salle County, Texas with a 100% working interest. During 2012, we expect to install pumping equipment to facilitate water removal and increase gas production.

In the Williston Basin, we participated in drilling three horizontal Bakken oil wells during 2011 with working interest ranging from 10% to 18%.  We expect to participate in drilling approximately five wells in 2012 within the Bakken formation.

 
12

 
In Mississippi, during 2011, we participated in the drilling of three 14,400 foot Hosston oil wells in the Parker Creek Field with an approximate 65% working interest.

During 2012, 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 2012 of between $35.0 million and $40.0 million.  We expect to spend 43% of the 2012 capital budget in the Permian Basin, 40% in the Williston Basin, 5% in Mississippi and 12% in all remaining areas.

The following table sets forth information with respect to wells completed during the years ended December 31, 2011, 2010 and 2009. 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 oil, natural gas, and NGLs regardless of whether they produce a reasonable rate of return.
 
   
Year Ended December 31,
 
   
2011
   
2010
   
2009
 
Gross wells:
                 
Productive
    15       8       1  
Dry
                 
Total
    15       8       1  
Net Development wells:
                       
Productive
    8.9       4.6       0.45  
Dry
                 
Total
    8.9       4.6       0.45  
Net Exploratory wells:
                       
Productive
                 
Dry
                 
Total
                 

 
Operations
 
 
Principal Customers
 
 
For the year ended December 31, 2011, sales of oil, natural gas and NGLs to Marathon Oil Company, Plains Marketing LP, Shell Trading (US) Company, Flint Hills Resources LP and Lewis Petro Properties Inc. accounted for approximately 22%, 11%, 8%, 6% and 5%, respectively, of our oil, natural gas and NGLs revenues. Our top five purchasers during the year ended December 31, 2011 therefore accounted for 52% of our total revenues. To the extent these and other customers reduce the volumes of oil, natural gas and NGLs 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 a substitute purchaser could be identified 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, 2011, 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 properties, but receive our share of revenues from the operator.

 
13

 
The marketing of heavy sour crude oil production from our Big Horn Basin properties is done through our Clearfork pipeline, which transports the crude oil to local and other refiners through connections to other interstate pipelines. Our Big Horn Basin 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 properties at the wellhead to third party gathering and marketing companies.

 
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. Additionally, we may acquire put options for which we pay the counterparty an option premium, equal to the fair value of the option at the purchase date. As each monthly contract settles, we receive the excess, if any, of the fixed floor over the floating rate. We also enter into basis swap contracts which guarantee a price differential between the NYMEX prices and our physical pricing points. We receive a payment from the counterparty or make a payment to the counterparty for the difference between the settled price differential and amounts stated under the terms of the contract. Furthermore, we may enter into collars where we pay the counterparty if the market price is above the ceiling price and the counterparty pays us if the market price is below the floor on a notional quantity. We also may enter into three-way collar contracts which combine a long put, a short put and a short call. The use of the long put combined with the short put allows us to sell a call at a higher price thus establishing a higher ceiling and limiting our exposure to future settlement payments while also restricting our downside risk to the difference between the long put and the short put if the price of NYMEX WTI crude oil drops below the price of the short put. This allows us to settle for WTI market plus the spread between the short put and the long put in a case where the market price has fallen below the short put fixed price. We also enter into swaption agreements, under which we provide options to counterparties to extend swap contracts into subsequent years. In deciding which type of derivative instrument to use, our management considers the relative benefit of each type against any cost that would be incurred, prevailing commodity market conditions and management’s view on future commodity pricing. The amount of oil and natural gas production which is hedged is determined by applying a percentage to the expected amount of production in our most current reserve report in a given year. Typically, management intends to hedge 70% to 85% of projected production up to a four year period. 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. Management will consider liquidating a derivative contract if they believe that they can take advantage of an unusual market condition allowing them to realize a current gain and then have the ability to enter into a new derivative contract in the future at or above the commodity price of the contract that was liquidated.

The following tables summarize commodity derivative contracts in place at December 31, 2011:
 
   
Year
2012
   
Year
2013
   
Year
2014
 
Gas Positions:
                 
Fixed Price Swaps:
                 
Notional Volume (MMBtu)
    5,929,932       6,460,500       452,500  
Fixed Price ($/MMBtu)
  $ 5.51     $ 5.24     $ 4.80  
Puts:
                       
Notional Volume (MMBtu)
    328,668              
Floor Price ($/MMBtu)
  $ 6.76     $     $  
Total Gas Positions:
                       
Notional Volume (MMBtu)
    6,258,600       6,460,500       452,500  
Price ($/MMBtu)
  $ 5.57     $ 5.24     $ 4.80  

   
Year
2012
   
Year
2013
   
Year
2014
 
Oil Positions:
             
 
 
Fixed Price Swaps:
                 
Notional Volume (Bbls)
    1,487,790       1,423,500       1,414,375  
Fixed Price ($/Bbl)
  $ 87.95     $ 89.17     $ 89.91  
Collars:
                       
Notional Volume (Bbls)
    411,750       82,125       12,000  
Floor Price ($/Bbl)
  $ 80.89     $ 88.89     $ 100.00  
Ceiling Price ($/Bbl)
  $ 99.47     $ 107.34     $ 116.20  
Three-Way Collars:
                       
Notional Volume (Bbls)
    640,500       688,650       164,250  
Floor Price ($/Bbl)
  $ 85.14     $ 90.91     $ 93.33  
Ceiling Price ($/Bbl)
  $ 101.70     $ 104.01     $ 105.00  
Put Sold ($/Bbl)
  $ 67.14     $ 65.57     $ 70.00  
Total Oil Positions:
                       
Notional Volume (Bbls)
    2,540,040       2,194,275       1,590,625  
Floor Price ($/Bbl)
  $ 86.10     $ 89.71     $ 90.34  


 
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As of December 31, 2011, the Company had the following open basis swap contracts:

   
Year
2012
   
Year
2013
   
Year
2014
 
Gas Positions:
                 
Notional Volume (MMBtu)
    915,000       912,500       452,500  
Weighted Avg. Basis Differential ($/MMBtu)(1)
  $ (0.32 )   $ (0.32 )   $ (0.32 )
                         
Oil Positions:
                       
Notional Volume (Bbls)
    84,000       84,000        
Weighted Avg. Basis Differential ($/Bbl) (2)
  $ 15.15     $ 9.60     $  

(1)  
Natural gas basis swap contracts represent a weighted average differential between prices against Rocky Mountains (CIGC) and NYMEX Henry Hub prices.
(2)  
Oil basis swap contracts represent a weighted average differential between prices against Light Louisiana Sweet Crude (LLS) and NYMEX WTI prices.

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
 
Gas Positions:
                       
Notional Volume (MMBtu)
                1,642,500        
Weighted Average Fixed Price ($/MMBtu)
  $     $     $ 5.69     $  
                                 
Oil Positions:
                               
Notional Volume (Bbls)
    137,250       196,350       127,750       328,500  
Weighted Average Fixed Price ($/Bbl)
  $ 100.00     $ 100.73     $ 95.00     $ 95.56  

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, 2011 (in thousands):

   
2012
   
2013
   
2014
   
2015 (1)
   
2016
 
Weighted Average Notional Amount
  $ 260,164     $ 310,000     $ 298,781     $ 197,932     $ 114,325  
Weighted Average Fixed LIBOR Rate
    1.47 %     1.54 %     1.52 %     1.24 %     1.16 %

 
(1)
The counterparty has the option to extend the termination date of a contract for a notional amount of $30.0 million at 2.25% to August 5, 2018.

 
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Additionally, we sold the option to a counterparty to enter into a $25.0 million LIBOR swap at 1.25% beginning September 7, 2012 through September 7, 2016.

 Counterparty Risk

At December 31, 2011, 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
   
Long-Term
Assets
   
Current
Liabilities
   
Long-Term Liabilities
   
Total Amount Due From/(Owed To) Counterparty at
December 31, 2011
 
Citibank, N.A. (A)
  $     $ 1,105     $ (421 )   $     $ 684  
Wells Fargo Bank N.A./Wachovia Bank, N.A. (AA-)
                (4,616 )     (1,866 )     (6,482 )
BNP Paribas (AA-)
    633             (1,402 )     (8,423 )     (9,192 )
The Bank of Nova Scotia (AA-)
    34             (220 )     (3,485 )     (3,671 )
BBVA Compass (A)
                      (221 )     (221 )
Credit Agricole (A)
    151             (5,931 )     (2,197 )     (7,977 )
Royal Bank of Canada (AA-)
    1,288                   (3,345 )     (2,057 )
Natixis (A)
    227                   (391 )     (164 )
Bank of America (A)
                (184 )     (625 )     (809 )
Total
  $ 2,333     $ 1,105     $ (12,774 )   $ (20,553 )   $ (29,889 )

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.
 
 
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Natural Gas Gathering
 
 
We own and operate a network of natural gas gathering systems in the Big Horn Basin area of operation. These systems gather and transport our natural gas and a small amount of third-party natural gas to larger gathering systems and intrastate, interstate and local distribution pipelines. Our network of natural gas gathering systems permits us to transport production from our wells with fewer interruptions and also minimizes any delays associated with a gathering company extending its lines to our wells. Our ownership and control of these lines enables us to:

·  
realize faster connection of newly drilled wells to the existing system;
·  
control pipeline operating pressures and capacity to maximize 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.

 
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 and Occupational 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, environmental protection, and the health and safety of employees. 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 permits before commencing drilling or other regulated activities;
     
 
·
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.
 
    
 
      
 
 
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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 NGLs 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 may 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 well drilling, construction, completion, water management activities, or waste handling, disposal or 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, 2011, 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 2012 or that will otherwise have a material impact on our financial position or results of operations.
 
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. For instance, in September 2010, the Natural Resources Defense Council filed a petition for rulemaking with the EPA requesting application of hazardous, rather than non-hazardous, requirements under RCRA to drilling fluids and produced waters but, to date, the EPA has not taken any action on the petition. 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, which cost increase could be significant.
 
 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 used on these properties in the past were standard in the industry at the time, hazardous substances, wastes, or petroleum hydrocarbons may 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.

 
18

 
Our 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, 2011, we have recorded $10.3 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 Discharges.   The Federal Water Pollution Control Act, as amended, or “Clean Water Act,” and analogous state laws impose restrictions and strict controls on the discharge of pollutants, including produced waters and other 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.

The primary federal law for oil spill liability is the Oil Pollution Act, as amended, or “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.  Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand, and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. We commonly use hydraulic fracturing as part of our operations. Hydraulic fracturing typically is regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority pursuant to the Safe Drinking Water Act over certain hydraulic fracturing activities involving the use of diesel. In addition, legislation has been introduced before Congress to provide for federal regulation of hydraulic fracturing under the Safe Drinking Water Act and to require disclosure of the chemicals used in the hydraulic fracturing process. Some states, including Texas and Wyoming, have adopted, and other states are considering adopting legal requirements that could impose more stringent permitting, public disclosure, or well construction requirements on hydraulic fracturing activities. We believe that we follow applicable standard industry practices and legal requirements for groundwater protection in our hydraulic fracturing activities. Nonetheless, if new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells.
 
In addition, certain governmental reviews are either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices, and a committee of the United States House of Representatives has conducted an investigation of hydraulic fracturing practices. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with initial results expected to be available by late 2012 and final results by 2014. Moreover, the EPA is developing effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities and plans to propose these standards by 2014. Other governmental agencies, including the U.S. Department of Energy and the U.S. Department of the Interior, are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the federal Safe Drinking Water Act or other regulatory mechanisms.
 
To our knowledge, there have been no citations, suits, or contamination of potable drinking water arising from our fracturing operations. We do not have insurance policies in effect that are intended to provide coverage for losses solely related to hydraulic fracturing operations; however, we believe our general liability and excess liability insurance policies would cover third-party claims related to hydraulic fracturing operations and associated legal expenses in accordance with, and subject to, the terms of such policies.
 
 
19

 
Air Emissions.   The Clean Air Act, as amended, and comparable state laws restrict the emission of air pollutants from many sources and also impose various monitoring and reporting requirements. These laws and their implementing regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with air permit requirements or utilize specific equipment or technologies to control emissions. Obtaining permits has the potential to delay the development of oil and natural gas projects. To date, we believe that no unusual difficulties have been encountered in obtaining air permits.  However, there is no assurance that in the future, we will not be required to incur capital expenditures in connection with maintaining or obtaining operating permits and approvals addressing air emission-related issues.  For example, in July 2011, the EPA proposed a range of new regulations that would establish new air emission controls for oil and natural gas production and natural gas processing, including, among other things, a new source performance standard for volatile organic compounds that would apply to hydraulically fractured wells, compressors, pneumatic controllers, condensate and crude oil storage tanks, and natural gas processing plants.  The EPA is under a court order to finalize these proposed regulations by April 3, 2012.

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.

Climate Changes.  In response to findings made by the EPA in December 2009 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 climatic changes, the EPA, has adopted regulations restricting emissions of GHGs under existing provisions of the federal Clean Air Act including one that requires a reduction in emissions of GHGs from motor vehicles and another that triggers construction and operating permit review for GHG emissions from certain large 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. These EPA rulemakings could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified facilities. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from certain sources including, among others, onshore and offshore oil and natural gas production facilities, which may include certain of our operations, on an annual basis. We are conducting monitoring of GHG emissions from our operations in accordance with the GHG emissions reporting rule and we believe that our monitoring and reporting activities are in substantial compliance with applicable reporting obligations.

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. 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.

Endangered Species Act Considerations.  The federal Endangered Species Act, as amended, or the “ESA,” restricts activities that may affect endangered or threatened species or their habitats. While some of our facilities or leased acreage may be located in areas that are designated as habitat for endangered or threatened species, we believe our operations are in substantial compliance with the ESA. If endangered species are located in areas of the underlying properties where we wish to conduct seismic surveys, development activities or abandonment operations, such work could be prohibited or delayed or expensive mitigation may be required.  Moreover, as a result of a settlement approved by the U.S. District Court for the District of Columbia on September 9, 2011, the U.S. Fish and Wildlife Service is required to make a determination on listing of more than 250 species as endangered or threatened under the ESA over the next six years, through the agency’s 2017 fiscal year.  The designation of previously unprotected species as threatened or endangered in areas where underlying property operations are conducted could cause us to incur increased costs arising from species protection measures or could result in limitations on our exploration and production activities that could have an adverse impact on our ability to develop and produce reserves.
 
 
20

 
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, the 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 NGLs 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 NGLs within its jurisdiction.
 
 Regulation of Transportation and Sales.   The availability, terms and cost of transportation significantly affect sales of oil, natural gas and NGLs. 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.

The ability to transport oil and NGLs 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.

 
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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 of each year, 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.

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 NGLs 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.
 
 
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State Regulation.  The various states regulate the drilling for, and the production, gathering and sale of, oil, natural gas and NGLs, 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 NGLs production is imposed at a rate of 9.26%, 6.0%, 4.5%, 3.0% and 3.75% in Montana, Wyoming, 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. Also, North Dakota currently imposes a 11.12% severance tax on gas production and 5.0% 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 NGLs 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, 2012, we had 110 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.
 
 
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 Annual Report. We make available on our 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.
 
 
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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 NGLs we produce;
 
·  
the price at which we are able to sell our oil, natural gas and NGLs production;
 
·  
the level of our operating costs;
 
·  
the level and success of our price risk management activities;
 
·  
the level of our interest expense which depends on the amount of our indebtedness and the interest payable thereon;
 
·  
the level of our capital expenditures; and
 
·  
voluntary or required payments on our debt agreements.
 
In addition, the actual amount of cash we will have available for distribution will depend on other factors, some of which are beyond our control, including:
 
·  
the level of our capital expenditures;
 
·  
our ability to make working capital borrowings under our financing arrangements to pay distributions;
 
·  
the cost of acquisitions, if any;
 
·  
our debt service requirements;
 
·  
fluctuations in our working capital needs;
 
·  
timing and collectibility of receivables;
 
·  
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.

 
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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 to refinance our reserve-based credit facility and other financing arrangements when they expire.

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.
 
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 NGLs reserves, which will take into account the prevailing oil, natural gas and NGLs 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. 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.

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

Our future distributions and proved reserves will be dependent upon the success of our efforts to prudently acquire, manage and develop oil and natural gas properties that conform to the acquisition profile described in this Annual Report.
 
In addition to ownership of the properties currently owned by us, unless we acquire properties in the future containing additional proved reserves or successfully develop proved reserves on our existing properties, our proved reserves will decline as the reserves attributable to the underlying properties are produced. In addition, if the costs to develop or operate our properties increase, the estimated proved reserves associated with properties will be reduced below the level that would otherwise be estimated. We will manage and develop our properties, and the ultimate value to us of such properties which we acquire will be dependent upon the price we pay and our ability to prudently acquire, manage and develop such properties. As a result, our future cash distributions will be dependent to a substantial extent upon our ability to prudently acquire, manage and develop such properties.
 
Suitable acquisition candidates may not be available on terms and conditions that we find acceptable, we may not be able to obtain financing for certain acquisitions, and acquisitions pose substantial risks to our businesses, financial conditions and results of operations. Even if future acquisitions are completed, the following are some of the risks associated with acquisitions, which could reduce the amount of cash available from the affected properties:
 
 
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·        some of the acquired properties may not produce revenues, reserves, earnings or cash flow at anticipated levels;
 
 
 
·        we may assume liabilities that were not disclosed or that exceed their estimates;
 
 
 
·        we may be unable to integrate acquired properties successfully and may not realize anticipated economic, operational and other benefits in a timely manner, which could result in substantial costs and delays or other operational, technical or financial problems;
 
 
 
·        acquisitions could disrupt our ongoing business, distract management, divert resources and make it difficult to maintain our current business standards, controls and procedures; and
 
 
·        we may incur additional debt related to future acquisitions.

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

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 NGLs production and the prices prevailing from time to time for oil, natural gas and NGLs. 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 NGLs 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. Additionally, we have recorded goodwill which represents the excess of the purchase price over the estimated fair value of the net assets acquired in the ENP Acquisition. Significant price declines could cause us to take one or more ceiling test write downs or cause us to record an impairment of goodwill, which would be reflected as non-cash charges against current earnings.

Oil, natural gas and NGLs 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, 2011 and December 31, 2011 ranged from a high of $113.39 to a low of $75.40 and the NYMEX natural gas spot price per MMBtu for the period January 1, 2011 to December 31, 2011 ranged from a high of $4.85 to a low of $2.99. As of February 28, 2012, the crude oil spot price per barrel was $106.59 and the NYMEX natural gas spot price per MMBtu was $2.52. 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 NGLs are subject to a variety of factors, including:

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

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

·  
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 NGLs;

·  
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.

 
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Declines in oil, natural gas and NGLs prices would not only reduce our revenue, but could reduce the amount of oil, natural gas and NGLs 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 or make distributions to our unitholders, 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. 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 NGLs prices and other factors have resulted, and in the future may result, in ceiling test or goodwill 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 NGLs 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 2012, we do not anticipate an impairment at March 31, 2012.

Additionally, we have recorded goodwill which represents the excess of the purchase price over the estimated fair value of the net assets acquired in the ENP Acquisition. Significant price declines could cause us to record an impairment of goodwill, which would be reflected as non-cash charge against current earnings.

 
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Our acquisition activities will subject us to certain risks.
 
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 recorded goodwill or 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.

We could lose our interests in future wells in our South Texas area 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 GAAP net income, which is affected by non-cash items. As a result, we may be unable to pay distributions even when we record net income, and we may be able to pay distributions during periods when we incur net losses.
 
Our estimated reserves are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.
 
No one can measure underground accumulations of oil or natural gas in an exact way. Oil and natural gas reserve engineering requires subjective estimates of underground accumulations of oil and/or natural gas and assumptions concerning future oil and natural gas prices, production levels, and operating and development costs. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may prove to be inaccurate. Independent petroleum engineers prepare estimates of our proved reserves. Some of our reserve estimates are made without the benefit of a lengthy production history, which are less reliable than estimates based on a lengthy production history. Also, the calculation of estimated reserves requires certain assumptions regarding future oil and natural gas prices, production levels, and operating and development costs, any of which assumptions may prove incorrect. Any significant variance from these assumptions by actual figures could greatly affect our estimates of reserves, the economically recoverable quantities of oil, natural gas and NGLs attributable to any particular group of properties, the classifications of reserves based on risk of recovery, and estimates of the future net cash flows. For example, if natural gas prices decline by $1.00 per MMBtu and oil prices declined by $6.00 per barrel, the standardized measure of our proved reserves as of December 31, 2011 would decrease from $1.5 billion to $1.3 billion, based on price sensitivity generated from an internal evaluation. Our standardized measure is calculated using unhedged oil and natural gas prices and is determined in accordance with the rules and regulations of the SEC. Numerous changes over time to the assumptions on which our reserve estimates are based, as described above, often result in the actual quantities of oil, natural gas and NGLs we ultimately recover being different from our reserve estimates.
 
 
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The present value of future net cash flows from our proved reserves is not necessarily the same as the current market value of our estimated proved reserves.
 
We base the estimated discounted future net cash flows from our proved reserves using a 12-month average price and costs in effect on the day of the estimate. However, actual future net cash flows from our oil and natural gas properties will be affected by factors such as:
 
 
·        the volume, pricing and duration of our oil and natural gas hedging contracts;

 
·        supply of and demand for oil, natural gas and NGLs;
 
 
 
·        actual prices we receive for oil, natural gas and NGLs;
 
 
 
·        our actual operating costs in producing oil, natural gas and NGLs;
 
 
 
·        the amount and timing of our capital expenditures;
 
 
 
·        the amount and timing of actual production; and
 
 
 
·        changes in governmental regulations or taxation.
 
 
The timing of both our production and our incurrence of expenses in connection with the development and production of oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves, which could adversely affect our business, results of operations, financial condition and our ability to make cash distributions to unitholders.
 
Our operations require substantial capital expenditures, which will reduce our cash available for distribution. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a decline in our reserves and adversely affect our ability to make distributions to our unitholders.
 
The oil and natural gas industry is capital intensive. We have made and ultimately expect to continue to make substantial capital expenditures in our business for the development, production and acquisition of oil, natural gas and NGLs reserves. These expenditures will reduce our cash available for distribution. We intend to finance our future capital expenditures with cash flow from operations and our financing arrangements. Our cash flow from operations and access to capital are subject to a number of variables, including:
 
 
·        our proved reserves;
 
 
 
·        the level of oil, natural gas and NGLs we are able to produce from existing wells;
 
 
 
·        the prices at which our oil, natural gas and NGLs are sold; and
 
 
 
·        our ability to acquire, locate and produce new reserves.
 
 
If our revenues or the borrowing base under our reserve-based credit facility decrease as a result of lower oil, natural gas and NGLs prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels or to replace or add to our reserves. Our reserve-based credit facility restricts our ability to obtain new debt financing. If additional capital is needed, we may not be able to obtain debt or equity financing on terms favorable to us, or at all. If cash generated by operations or available under our reserve-based credit facility is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our prospects, which in turn could lead to a possible decline in our reserves and production and a reduction in our cash available for distribution.
 
Our business depends on gathering and compression facilities owned by third parties and transportation facilities owned by third-party transporters and we rely on third parties to gather and deliver our oil, natural gas and NGLs to certain designated interconnects with third-party transporters. Any limitation in the availability of those facilities or delay in providing interconnections to newly drilled wells would interfere with our ability to market the oil, natural gas and NGLs we produce and could reduce our revenues and cash available for distribution.
 
 
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The marketability of our oil, natural gas and NGLs production depends in part on the availability, proximity and capacity of pipeline systems owned by third parties in the respective operating areas. The amount of natural gas that can be produced and sold is subject to curtailment in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, physical damage to the gathering, compression or transportation system, or lack of contracted capacity on such systems. The curtailments arising from these and similar circumstances may last from a few days to several months. In many cases, we are provided only with limited, if any, notice as to when these circumstances will arise and their duration. In addition, some of our wells are drilled in locations that are not serviced by gathering and transportation pipelines, or the gathering and transportation pipelines in the area may not have sufficient capacity to transport the additional production. As a result, we may not be able to sell the natural gas production from these wells until the necessary gathering and transportation systems are constructed. Any significant curtailment in gathering system or pipeline capacity, or significant delay in the construction of necessary gathering, compression and transportation facilities, could reduce our revenues and cash available for distribution.

Our sales of oil, natural gas and NGLs and other energy commodities, and related hedging activities, expose us to potential regulatory risks.

The Federal Trade Commission (“FTC”), Federal Regulatory Commission (“FERC”) and the Commodities Futures Trading Commission (“CFTC”) hold statutory authority to monitor certain segments of the physical and futures energy commodities markets. These agencies have imposed broad regulations prohibiting fraud and manipulation of such markets. With regard to our physical sales of oil, natural gas and NGLs or other energy commodities, and any related hedging activities that we undertake, we are required to observe the market-related regulations enforced by these agencies, which hold substantial enforcement authority. Our sales may also be subject to certain reporting and other requirements. Failure to comply with such regulations, as interpreted and enforced, could have a material adverse effect on our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.

We are subject to FERC requirements related to our use of capacity on natural gas pipelines that are subject to FERC regulation. Any failure on our part to comply with the FERC’s regulations and policies, or with an interstate pipeline’s tariff, could result in the imposition of civil and criminal penalties.

Climate change legislation and regulatory initiatives restricting emissions of greenhouse gases may adversely affect our operations, our cost structure, or the demand for oil and natural gas.

In response to findings made by the EPA in December 2009 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 climatic changes, the EPA, has adopted regulations under existing provisions of the federal Clean Air Act including one that requires a reduction in emissions of GHGs from motor vehicles and another that triggers 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 Prevention of Significant Deterioration (“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. These EPA rulemakings could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified facilities.  In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from certain sources including, among others, onshore and offshore oil and natural gas production facilities, which may include certain of our operations on an annual basis. Congress has from time to time actively 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. The adoption of any 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 provision of services.
 
 
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The adoption of derivatives legislation by the United States Congress could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.
 
The United States Congress adopted comprehensive financial reform legislation that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The new legislation was signed into law by the President on July 21, 2010 and requires the CFTC, the SEC and other regulators to promulgate rules and regulations implementing the new legislation. In December 2011, the CFTC extended temporary exemptive relief for certain regulations applicable to swaps, until no later than July 16, 2012. The CFTC has issued final regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. Certain bona fide hedging transactions would be exempt from these position limits. It is not possible at this time to predict when the CFTC will make these regulations effective. The financial reform legislation may also require us to comply with margin requirements and with certain clearing and trade-execution requirements in connection with our derivative activities, although the application of those provisions to us is uncertain at this time. The financial reform legislation may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty. The legislation and any new regulations could significantly increase the cost of derivative contracts (including from swap recordkeeping and reporting requirements and through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures or to make distributions. Finally, the legislation was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have material, adverse effect on us, our financial condition, and our results of operations.

We depend on certain key customers for sales of our oil, natural gas and NGLs. To the extent these and other customers reduce the volumes of oil, natural gas and NGLs they purchase from us, or to the extent these customers cease to be creditworthy, our revenues and cash available for distribution could decline.
 
For the year ended December 31, 2011, sales of oil, natural gas and NGLs to Marathon Oil Company, Plains Marketing LP, Shell Trading (US) Company, Flint Hills Resources, LP and Lewis Petro Properties Inc. accounted for approximately 22%, 11%, 8%, 6% and 5%, respectively, of our oil, natural gas and NGLs revenues. Our top five purchasers during the year ended December 31, 2011 therefore accounted for 52% of our total revenues. To the extent these and other customers reduce the volumes of oil, natural gas and NGLs 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.
 
We are subject to compliance with environmental and occupational safety and health laws and regulations that may expose us to significant costs and liabilities.
 
The operations of our wells are subject to stringent and complex federal, state and local laws and regulations governing the discharge of materials into the environment, environmental protection, and the health and safety of employees.  These laws and regulations may impose numerous obligations on our operations including the acquisition of permits, including drilling permits, to conduct regulated activities; the incurrence of capital expenditures to mitigate or prevent releases of materials from our facilities; restriction of types, quantities and concentration of materials that can be released into the environment; limitation or prohibition of construction and operating activities in environmental sensitive areas such as wetlands, wilderness regions and other protected areas; the imposition of substantial liabilities for pollution resulting from our operations; and the application of specific health and safety criteria addressing worker protection. Numerous governmental authorities, such as the EPA and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, often requiring difficult and costly actions.
 
 Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements, and the issuance of orders enjoining future operations. Certain environmental statutes impose strict, and under certain circumstances, joint and several liability for costs required to clean up and restore sites where hazardous substances or wastes have been disposed of or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property or natural resource damage allegedly caused by the release of hazardous substances or other waste products into the environment.
 
We may incur significant environmental costs and liabilities due to the nature of our business and the petroleum hydrocarbons, hazardous substances and wastes resulting from or associated with operation of our wells. For example, an accidental release of petroleum hydrocarbons from one of our wells could subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury, property and natural resource damage, and fines or penalties for related violations of environmental laws or regulations. Moreover, the possibility exists that stricter laws, regulations or enforcement policies could significantly increase our compliance costs and the cost of any remediation that may become necessary. We may not be able to recover some or any of these costs from insurance. Please read “Item 1. Business—Operations—Environmental and Occupational Health Safety Matters.”

 
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Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and operating restrictions or delays in the completion of oil and natural gas wells.
 
Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. We commonly use hydraulic fracturing as part of our operations. Hydraulic fracturing typically is regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority pursuant to the Safe Drinking Water Act over certain hydraulic fracturing activities involving the use of diesel.  In addition, legislation has been introduced before Congress to provide for federal regulation of hydraulic fracturing under the Safe Drinking Water Act and to require disclosure of the chemicals used in the hydraulic fracturing process. Some states, including Texas and Wyoming, have adopted, and other states are considering adopting legal requirements that could impose more stringent permitting public disclosure, or well construction requirements on hydraulic fracturing activities. If new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells.
 
In addition, certain governmental reviews are either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices, and a committee of the United States House of Representatives has conducted an investigation of hydraulic fracturing practices. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with initial results expected to be available by late 2012 and final results by 2014. Moreover, the EPA is developing effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities and plans to propose these standards by 2014. Other governmental agencies, including the U.S. Department of Energy and the U.S. Department of the Interior, are evaluating various other aspects of hydraulic fracturing.  These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the federal Safe Drinking Water Act or other regulatory mechanisms.
 
Locations that we or the operators of our properties decide to drill may not yield oil or natural gas in commercially viable quantities.
 
 
The cost of drilling, completing and operating a well is often uncertain, and cost factors can adversely affect the economics of a well. Our efforts will be uneconomical if we or the operators of our properties drill dry holes or wells that are productive but do not produce enough to be commercially viable after drilling, operating and other costs. If we or the operators of our properties drill future wells that we identify as dry holes, our drilling success rate would decline and may adversely affect our results of operations and our ability to pay future cash distributions at expected levels.
 
Many of our leases are in areas that have been partially depleted or drained by offset wells.
 
 
Many of our leases are in areas that have already been partially depleted or drained by earlier offset drilling. This may inhibit our ability to find economically recoverable quantities of oil or natural gas in these areas.
 
Our identified drilling location inventories are scheduled out over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling, resulting in temporarily lower cash from operations, which may impact our ability to pay distributions.
 
Our management has specifically identified and scheduled drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. As of December 31, 2011, we have identified 442 proved undeveloped drilling locations and over 205 additional drilling locations. These identified drilling locations represent a significant part of our strategy. Our ability to drill and develop these locations depends on a number of factors, including the availability of capital, seasonal conditions, regulatory approvals, natural gas prices, drilling and operating costs and drilling results. In addition, D&M has not assigned any proved reserves to the over 205 unproved drilling locations we have identified and scheduled for drilling and therefore there may exist greater uncertainty with respect to the success of drilling wells at these drilling locations. Our final determination on whether to drill any of these drilling locations will be dependent upon the factors described above as well as, to some degree, the results of our drilling activities with respect to our proved drilling locations. Because of these uncertainties, we do not know if the numerous drilling locations we have identified will be drilled within our expected timeframe or will ever be drilled or if we will be able to produce oil or natural gas from these or any other potential drilling locations. As such, our actual drilling activities may materially differ from those presently identified, which could adversely affect our business.
 
 
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Drilling for and producing oil, natural gas and NGLs are high risk activities with many uncertainties that could adversely affect our financial condition or results of operations and, as a result, our ability to pay distributions to our unitholders.
 
Our drilling activities are subject to many risks, including the risk that we will not discover commercially productive reservoirs. Drilling for oil or natural gas can be uneconomical, not only from dry holes, but also from productive wells that do not produce sufficient revenues to be commercially viable. In addition, our drilling and producing operations may be curtailed, delayed or canceled as a result of other factors, including:
 
 
·
the high cost, shortages or delivery delays of equipment and services;
     
 
·
shortages of or delays in obtaining water for hydraulic fracturing operations;
     
 
·
unexpected operational events;
     
 
·
adverse weather conditions;

 
·
facility or equipment malfunctions;
     
 
·
title problems;
     
 
·
pipeline ruptures or spills;
     
 
·
compliance with environmental and other governmental requirements;
     
 
·
unusual or unexpected geological formations;
     
 
·
loss of drilling fluid circulation;
     
 
·
formations with abnormal pressures;
     
 
·
environmental hazards, such as oil, natural gas or well fluids spills or releases, pipeline or tank ruptures and discharges of toxic gas;
     
 
·
fires;
     
 
·
blowouts, craterings and explosions;
     
 
·
uncontrollable flows of oil, natural gas or well fluids; and
     
 
·
pipeline capacity curtailments.
 
 
Any of these events can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination, loss of wells and regulatory penalties.
 
We ordinarily maintain insurance against various losses and liabilities arising from our operations; however, insurance against all operational risks is not available to us. Additionally, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses could therefore occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could have a material adverse impact on our business activities, financial condition and results of operations.
 
 
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We may incur substantial additional debt in the future to enable us to pursue our business plan and to pay distributions to our unitholders.
 
Our business requires a significant amount of capital expenditures to maintain and grow production levels. Commodity prices have historically been volatile, and we cannot predict the prices we will be able to realize for our production in the future. As a result, we may borrow, to the extent available, significant amounts under our reserve-based credit facility in the future to enable us to pay quarterly distributions. Significant declines in our production or significant declines in realized oil, natural gas and NGLs prices for prolonged periods and resulting decreases in our borrowing base may force us to reduce or suspend distributions to our unitholders.
 
If we borrow to pay distributions, we are distributing more cash than we are generating from our operations on a current basis. This means that we are using a portion of our borrowing capacity under our reserve-based credit facility to pay distributions rather than to maintain or expand our operations. If we use borrowings under our reserve-based credit facility to pay distributions for an extended period of time rather than toward funding capital expenditures and other matters relating to our operations, we may be unable to support or grow our business. Such a curtailment of our business activities, combined with our payment of principal and interest on our future indebtedness to pay these distributions, will reduce our cash available for distribution on our common units. If we borrow to pay distributions during periods of low commodity prices and commodity prices remain low, we may have to reduce or suspend our distribution in order to avoid excessive leverage and debt covenant violations.
 
Seasonal weather conditions and lease stipulations adversely affect our ability to conduct drilling activities in some of the areas where we operate.
 
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. Additionally, many municipalities impose weight restrictions on the paved roads that lead to our jobsites due to the muddy conditions caused by spring thaws. This limits our access to these jobsites and our ability to service wells in these areas. 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.
 
Our price risk management activities could result in financial losses or could reduce our cash flow, which may adversely affect our ability to pay distributions to our unitholders.
 
We enter into derivative contracts to reduce the impact of oil and natural gas price volatility on our cash flow from operations. Currently, we use a combination of fixed-price swaps, basis swaps, swaptions, put options, NYMEX collars and three-way collars to mitigate the volatility of future oil and natural gas prices received. Please read “Item 1. Business— Operations— Price Risk and Interest Rate Management Activities” and “Item 7A. Quantitative and Qualitative Disclosures About Market Risk.”
 
Our actual future production may be significantly higher or lower than we estimate at the time we enter into derivative contracts for such period. If the actual amount of production is higher than we estimate, we will have greater commodity price exposure than we intended. If the actual amount of production is lower than the notional amount that is subject to our derivative financial instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of the cash flow from our sale of the underlying physical commodity, resulting in a substantial diminution of our liquidity. As a result of these factors, our hedging activities may not be as effective as we intend in reducing the volatility of our cash flows, and in certain circumstances may actually increase the volatility of our cash flows. In addition, our price risk management activities are subject to the following risks:
 
 
·      a counterparty may not perform its obligation under the applicable derivative instrument;
 
 
·      there may be a change in the expected differential between the underlying commodity price in the derivative instrument and the actual price received; and
 
 
·      the steps we take to monitor our derivative financial instruments may not detect and prevent violations of our risk management policies and procedures.
 
 
We are exposed to trade credit risk in the ordinary course of our business activities.

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

 
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We depend on senior management personnel, each of whom would be difficult to replace.
 
 
We depend on the performance of Scott W. Smith, our President and Chief Executive Officer, Richard A. Robert, our Executive Vice President and Chief Financial Officer and Britt Pence, our Senior Vice President of Operations. We maintain no key person insurance for either Mr. Smith, Mr. Robert or Mr. Pence. The loss of any or all of Messrs. Smith, Robert and Pence could negatively impact our ability to execute our strategy and our results of operations.
 
We may be unable to compete effectively with larger companies, which may adversely affect our ability to generate sufficient revenue to allow us to pay distributions to our unitholders.
 
The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Many of our larger competitors not only drill for and produce oil, natural gas and NGLs, but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for oil and natural gas properties and evaluate, bid for and purchase a greater number of properties than our financial or human resources permit. In addition, these companies may have a greater ability to continue drilling activities during periods of low oil, natural gas and NGLs prices and to absorb the burden of present and future federal, state, local and other laws and regulations. Our inability to compete effectively with larger companies could have a material adverse impact on our business activities, financial condition and results of operations.
 
We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of doing business.
 
Our operations are regulated extensively at the federal, state and local levels. Environmental and other governmental laws and regulations have increased the costs to plan, design, drill, install, operate and abandon oil and natural gas wells. Under these laws and regulations, we could also be liable for personal injuries, property and natural resource damage and other damages. Failure to comply with these laws and regulations may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Moreover, public interest in environmental protection has increased in recent years, and environmental organizations have opposed, with some success, certain drilling projects.
 
Part of the regulatory environment in which we operate includes, in some cases, legal requirements for obtaining environmental assessments, environmental impact studies and/or plans of development before commencing drilling and production activities. In addition, our activities are subject to the regulations regarding conservation practices and protection of correlative rights. These regulations affect our operations and limit the quantity of natural gas we may produce and sell. A major risk inherent in our drilling plans is the need to obtain drilling permits from state and local authorities. Delays in obtaining regulatory approvals or drilling permits, the failure to obtain a drilling permit for a well or the receipt of a permit with unreasonable conditions or costs could have a material adverse effect on our ability to develop our properties. Additionally, the oil and natural gas regulatory environment could change in ways that might substantially increase the financial and managerial costs of compliance with these laws and regulations and, consequently, adversely affect our profitability. At this time, we cannot predict the effect of this increase on our results of operations. Furthermore, we may be put at a competitive disadvantage to larger companies in our industry that can spread these additional costs over a greater number of wells and larger operating staff. Please read “Item1. Business—Operations—Environmental and Occupational Health and Safety Matters” and “Item 1. Business—Operations—Other Regulation of the Oil and Natural Gas Industry” for a description of the laws and regulations that affect us.
 
Shortages of drilling rigs, supplies, oilfield services, equipment and crews could delay our operations and reduce our cash available for distribution.
 
Higher oil, natural gas and NGLs prices generally increase the demand for drilling rigs, supplies, services, equipment and crews, and can lead to shortages of, and increasing costs for, drilling equipment, services and personnel. In the past, we and other oil, natural gas and NGLs companies have experienced higher drilling and operating costs. Shortages of, or increasing costs for, experienced drilling crews and equipment and services could restrict our ability to drill the wells and conduct the operations that we currently have planned. Sustained periods of lower oil, natural gas and NGLs prices could bring about the closure or downsizing of entities providing drilling services, supplies, oil field services, equipment and crews. Any delay in the drilling of new wells or significant increase in drilling costs could reduce our revenues and cash available for distribution.
 
 
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Risks Related to Our Structure
 
 
We may issue additional units without unitholder approval, which would dilute their existing ownership interests.
 
 
We may issue an unlimited number of limited liability company interests of any type, including units, without the approval of our unitholders.
 
The issuance of additional units or other equity securities may have the following effects:
 
·
the proportionate ownership interest of unitholders in us may decrease;
   
·
the amount of cash distributed on each unit may decrease;
   
·
the relative voting strength of each previously outstanding unit may be diminished; and
   
·
the market price of the units may decline.
 
Our limited liability company agreement restricts the voting rights of unitholders owning 20% or more of our units.
 
Our limited liability company agreement restricts the voting rights of unitholders by providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than persons who acquire such units with the prior approval of the board of directors, cannot vote on any matter. Our limited liability agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting unitholders’ ability to influence the manner or direction of management.
 
Our limited liability company agreement provides for a limited call right that may require unitholders to sell their units at an undesirable time or price.
 
If, at any time, any person owns more than 90% of the units then outstanding, such person has the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the remaining units then outstanding at a price not less than the then-current market price of the units. As a result, unitholders may be required to sell their units at an undesirable time or price and therefore may receive a lower or no return on their investment. Unitholders may also incur tax liability upon a sale of their units.
 
The price of our common units could be subject to wide fluctuations, unitholders could lose a significant part of their investment.
 
During 2011, our unit price fluctuated from a closing high of $33.09 on April 29, 2011 to a closing low of $23.29 on October 4, 2011. The market price of our common units is subject to wide fluctuations in response to a number of factors, most of which we cannot control, including:
 
·
fluctuations in broader securities market prices and volumes, particularly among securities of oil and natural gas companies and securities of publicly traded limited partnerships and limited liability companies;
   
·
changes in general conditions in the U.S. economy, financial markets or the oil and natural gas industry;
   
·
changes in securities analysts’ recommendations and their estimates of our financial performance;
   
·
the public’s reaction to our press releases, announcements and our filings with the SEC;
   
·
changes in market valuations of similar companies;
   
·
departures of key personnel;
   
·
commencement of or involvement in litigation;
   
·
variations in our quarterly results of operations or those of other oil and natural gas companies;
   
·
variations in the amount of our quarterly cash distributions; and
   
·
future issuances and sales of our units.
 
 
 
 
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In recent years, the securities market has experienced extreme price and volume fluctuations. This volatility has had a significant effect on the market price of securities issued by many companies for reasons unrelated to the operating performance of these companies. Future market fluctuations may result in a lower price of our common units.
 
Unitholders may have liability to repay distributions.
 
 
Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 18-607 of the Delaware Revised Limited Liability Company Act, or the “Delaware Act,” we may not make a distribution to unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of an impermissible distribution, members or unitholders who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited liability company for the distribution amount. A purchaser of common units who becomes a member or unitholder is liable for the obligations of the transferring member to make contributions to the limited liability company that are known to such purchaser of units at the time it became a member and for unknown obligations if the liabilities could be determined from our limited liability company agreement.
 
An increase in interest rates may cause the market price of our common units to decline.
 
 
Like all equity investments, an investment in our common units is subject to certain risks. In exchange for accepting these risks, investors may expect to receive a higher rate of return than would otherwise be obtainable from lower-risk investments. Accordingly, as interest rates rise, the ability of investors to obtain higher risk-adjusted rates of return by purchasing government-backed debt securities may cause a corresponding decline in demand for riskier investments generally, including yield-based equity investments such as publicly-traded limited liability company interests. Reduced demand for our units resulting from investors seeking other more favorable investment opportunities may cause the trading price of our common units to decline.
 
 
Tax Risks to Unitholders
 
 
Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If the IRS were to treat us as a corporation for federal income tax purposes or we were to become subject to additional amounts of entity-level taxation for state tax purposes, taxes paid, if any, would reduce the amount of cash available for distribution to unitholders.
 
The anticipated after-tax economic benefit of an investment in our units depends largely on us being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes.
 
Despite the fact that we are a limited liability company (LLC) under Delaware law, a publicly traded LLC such as us may be treated as a corporation for federal income tax purposes unless it satisfies a “qualifying income” requirement.  Failing to meet the qualifying income requirement or a change in current law may cause us to be treated as a corporation for federal income tax purposes.
 
If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rates, currently at a maximum rate of 35%, and would likely pay state income tax at varying rates. Distributions to unitholders would generally be taxed again as corporate distributions, and no income, gain, loss, deduction or credit would flow through to unitholders. Because a tax may be imposed on us as a corporation, our cash available for distribution to our unitholders could be reduced. Therefore, treatment of us or ENP as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our common units.
 
Current law or our business may change so as to cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to entity-level taxation. At the federal level, legislation has been recently considered that would have eliminated partnership tax treatment for certain publicly traded LLCs. Although such legislation did not appear as if it would have applied to us as proposed, it could be reconsidered in a manner that would apply to us. We are unable to predict whether any of these changes or other proposals will be reintroduced or will ultimately be enacted. Moreover, any modification to the federal income tax laws and interpretations thereof may or may not be applied retroactively. Any such changes could negatively impact the value of an investment in our units. At the state level, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships and limited liability companies to entity-level taxation through the imposition of state income, franchise or other forms of taxation. For example, we are required to pay Texas franchise tax which is assessed on Texas sourced taxable margin defined as the lesser of (i) 70% of total revenue or (ii) total revenue less (a) cost of goods sold or (b) compensation and benefits. If any other state were to impose a tax upon us as an entity, the cash available for distribution to our unitholders would be reduced.
 
 
37

 
If the IRS contests the federal income tax positions we take, the market for our units may be adversely impacted and the costs of any IRS contest will reduce our cash available for distribution.
 
We have not requested, and do not plan to request, a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes. The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take and a court may disagree with some or all of those positions. Any contest with the IRS may materially and adversely impact the market for our units and the price at which they trade. In addition, our costs of any contest with the IRS will result in a reduction in cash available for distribution to our unitholders and thus will be borne indirectly by our unitholders.
 
Unitholders may be required to pay taxes on income from us even if they do not receive any cash distributions from us.
 
 
Because our unitholders will be treated as partners in us for federal income tax purposes to whom we will allocate taxable income which could be different in amount than the cash we distribute, unitholders will be required to pay federal income taxes and, in some cases, state and local income taxes on their share of our taxable income, whether or not they receive cash distributions from us. Unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from their share of our taxable income.
 
Tax gain or loss on disposition of our common units could be more or less than expected.
 
 
If unitholders sell their common units, they will recognize a gain or loss equal to the difference between the amount realized and their tax basis in those common units. Because distributions in excess of a unitholder’s allocable share of our net taxable income decreases the tax basis in the unitholder’s common units, the amount, if any, of such prior excess distributions with respect to the units they sell will, in effect, become taxable income to them if they sell such units at a price greater than their tax basis in those units, even if the price they receive is less than their original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation deductions. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if a unitholders sells their units, they may incur a tax liability in excess of the amount of cash they receive from the sale.
 
Tax-exempt entities and non-U.S. persons face unique tax issues from owning units that may result in adverse tax consequences to them.
 
Investment in units by tax-exempt entities, including employee benefit plans, individual retirement accounts (known as IRAs) and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to such a unitholder. Distributions to non-U.S. persons will be reduced by withholding taxes imposed at the highest effective applicable tax rate, and non-U.S. persons will be required to file U.S. federal income tax returns and pay tax on their share of our taxable income. If you are a tax exempt entity or a non-U.S. person, you should consult your tax advisor before investing in our units.
 
We treat each purchaser of our common units as having the same tax benefits without regard to the actual units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.
 
Because we cannot match transferors and transferees of common units and because of other reasons, we will adopt depreciation and amortization positions that may not conform with all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain on the sale of common units and could have a negative impact on the value of our common units or result in audits of and adjustments to our unitholders’ tax returns.
 
We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.
 
  We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury Regulations. The U.S. Treasury Department has issued proposed Treasury Regulations that provide a safe harbor pursuant to which publicly traded partnerships may use a similar monthly simplifying convention to allocate tax items. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method we have adopted. If the IRS were to challenge this method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.
 
 
38

 
A unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of those units. If so, he would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.
 
Because a unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of the loaned units, he may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.
 
The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.
 
We will be considered to have constructively terminated as a partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of determining whether the 50% threshold has been met, multiple sales of the same interest will be counted only once. Our termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders receiving two Schedules K-1) for one fiscal year and could result in a deferral of depreciation deductions allowable in computing our taxable income.  In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination.  Our termination currently would not affect our classification as a partnership for federal income tax purposes but instead, we would be treated as a new partnership for federal income tax purposes.  If treated as a new partnership, we must make new tax election and could be subject to penalties if we are unable to determine that a termination occurred. The IRS has recently announced a relief procedure whereby if a publicly traded partnership that has technically terminated requests and the IRS grants special relief, among other things, the partnership may be permitted to provide only a single Schedule K-1 to unitholders for the tax year in which the termination occurs.
 
Certain U.S. federal income tax deductions currently available with respect to oil and gas exploration and development may be eliminated as a result of future legislation.
 
The Fiscal Year 2013 Budget proposed by the President recommends the elimination of certain key U.S. federal income tax incentives currently available to oil and gas exploration and production companies, and legislation has been introduced in Congress which would implement many of these proposals. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain domestic production activities, and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective. The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil and gas exploration and development, and any such change could increase the taxable income allocable to our unitholders and negatively impact the value of an investment in our units. 

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

 
39

 
 
None.
 
 
A description of our properties is included in “Item 1. Business,” and is incorporated herein by reference.

 We have offices in Houston, Ft. Worth and Odessa, Texas; and Powell, Wyoming. As of December 31, 2011, the lease for the Houston office covered approximately 21,428 square feet of office space and runs through February 28, 2013. Our leases for the Ft. Worth and Odessa offices cover approximately 7,315 square feet and 3,250 square feet of office space, respectively, and run through December 31, 2015 and August 31, 2014, respectively. The total annual costs of our office leases for 2011 was approximately $0.9 million.

We believe that we have satisfactory title to the properties owned and used in our businesses, subject to liens for taxes not yet payable, liens incident to minor encumbrances, liens for credit arrangements and easements and restrictions that do not materially detract from the value of these properties, our interests in these properties, or the use of these properties in our businesses. We believe that our properties are adequate and suitable for the conduct of our business in the future.
 
 
The Company is a defendant in legal proceedings arising in the normal course of our business. While the outcome and impact of such legal proceedings on the Company cannot be predicted with certainty, management does not believe that it is probable that the outcome of any action will have a material adverse effect on the Company’s consolidated financial position, results of operations or cash flow. We are also currently a party to pending litigation related to the ENP Merger discussed below. In addition, we are not aware of any legal or governmental proceedings against us, or contemplated to be brought against us, under the various environmental protection statutes to which we are subject.
 
On March 29, 2011, John O’Neal, a purported unitholder of ENP, filed a putative class action petition in the 125th Judicial District of Harris County, Texas on behalf of unitholders of ENP. Similar petitions were filed on April 4, 2011 by Jerry P. Morgan and on April 5, 2011 by Herbert F. Rower in other Harris County district courts. The O’Neal, Morgan, and Rower lawsuits were consolidated on June 5, 2011 as John O’Neal v. Encore Energy Partners, L.P., et al., Case Number 2011-19340, which is pending in the 125th Judicial District Court of Harris County. On July 28, 2011, Michael Gilas filed a class action petition in intervention. On July 26, 2011, the current plaintiffs in the consolidated O’Neal action filed an amended putative class action petition against ENP, ENP GP, Scott W. Smith, Richard A. Robert, Douglas Pence, W. Timothy Hauss, John E. Jackson, David C. Baggett, Martin G. White, and Vanguard. That putative class action petition and Gilas’s petition in intervention both allege that the named defendants are (i) violating duties owed to ENP’s public unitholders by, among other things, failing to properly value ENP and failing to protect against conflicts of interest or (ii) are aiding and abetting such breaches. Plaintiffs seek an injunction prohibiting the merger from going forward and compensatory damages if the merger is consummated. On October 3, 2011, the Court appointed Bull & Lifshitz, counsel for plaintiff-intervenor Gilas, as interim lead counsel on behalf of the putative class. On October 21, 2011, the court signed an order staying this lawsuit pending resolution of the Delaware State Court Action (defined below), subject to plaintiffs’ right to seek to lift the stay for good cause. The defendants named in the Texas lawsuits intend to defend vigorously against them.

On April 5, 2011, Stephen Bushansky, a purported unitholder of ENP, filed a putative class action complaint in the Delaware Court of Chancery on behalf of the unitholders of ENP. Another purported unitholder of ENP, William Allen, filed a similar action in the same court on April 14, 2011. The Bushansky and Allen actions have been consolidated under the caption In re: Encore Energy Partners LP Unitholder Litigation, C.A. No. 6347-VCP (the “Delaware State Court Action”). On December 28, 2011, those plaintiffs jointly filed their second amended consolidated class action complaint naming as defendants ENP, Scott W. Smith, Richard A. Robert, Douglas Pence, W. Timothy Hauss, John E. Jackson, David C. Baggett, Martin G. White, and Vanguard. That putative class action complaint alleges, among other things, that defendants breached the partnership agreement by recommending a transaction that is not fair and reasonable. Plaintiffs seek compensatory damages. Vanguard has filed a motion to dismiss this lawsuit and it intends to defend vigorously against this lawsuit.

 
40

 
On August 28, 2011, Herman Goldstein, a purported unitholder of ENP, filed a putative class action complaint against ENP, ENP GP, Scott W. Smith, Richard A. Robert, Douglas Pence, W. Timothy Hauss, John E. Jackson, David C. Baggett, Martin G. White, and Vanguard in the United States District Court for the Southern District of Texas on behalf of the unitholders of ENP. That lawsuit is captioned Goldstein v. Encore Energy Partners LP. et al., United States District Court for the Southern District of Texas, 4:11-cv-03198.  Goldstein alleges that the named defendants violated Sections 14(a) and 20(a) of the Securities Exchange Act of 1934 as amended (the “Exchange Act”) and Rule 14a-9 promulgated thereunder by disseminating a false and materially misleading proxy statement in connection with the merger. Plaintiff seeks an injunction prohibiting the proposed merger from going forward. Currently, the parties are awaiting the appointment of a lead plaintiff in this lawsuit. The defendants named in this lawsuit intend to defend vigorously against it.

On September 6, 2011, Donald A. Hysong, a purported unitholder of ENP, filed a putative class action complaint against ENP, ENP GP, Scott W. Smith, Richard A. Robert, Douglas Pence, W. Timothy Hauss, John E. Jackson, David C. Baggett, Martin G. White, and Vanguard on behalf of the unitholders of ENP in the United States District Court for the District of Delaware that is captioned Hysong v. Encore Energy Partners LP. et al., 1:11-cv-00781-SD. Hysong alleged that the named defendants violated either Section 14(a) of the Exchange Act and Rule 14a-9 promulgated thereunder or Section 20(a) of the Securities Exchange Act of 1934 by disseminating a false and materially misleading proxy statement in connection with the merger. On September 14, 2011, in accordance with recent practice in Delaware, that case was assigned to Judge Stewart Dalzell of the Eastern District of Pennsylvania. On November 10, 2011, Judge Dalzell entered an order dismissing the lawsuit and entering judgment in the defendants’ favor.

Vanguard cannot predict the outcome of these or any other lawsuits that might be filed subsequent to the date of this filing, nor can Vanguard predict the amount of time and expense that will be required to resolve these lawsuits. Vanguard, ENP and the other defendants named in these lawsuits intend to defend vigorously against these and any other actions. 

 
MINE SAFETY DISCLOSURES

Not applicable.



 
ITEM 5.
MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
 
Our common units are traded on the New York Stock Exchange under the symbol “VNR.” On March 1, 2012, there were 53,469,703 common units outstanding and approximately twenty seven unitholders, which does not include beneficial owners whose units are held by a clearing agency, such as a broker or a bank. On March 1, 2012, the market price for our common units was $27.79 per unit, resulting in an aggregate market value of units held by non-affiliates of approximately $1.4 billion The following table presents the high and low sales price for our common units during the periods indicated.
 
   
Common Units
 
   
High
   
Low
 
2011
           
Fourth Quarter
  $ 29.50     $ 21.86  
Third Quarter
  $ 31.75     $ 22.79  
Second Quarter
  $ 33.67     $ 26.10  
First Quarter
  $ 33.41     $ 28.23  
2010
               
Fourth Quarter
  $ 29.76     $ 24.98  
Third Quarter
  $ 26.46     $ 19.05  
Second Quarter
  $ 25.27     $ 16.94  
First Quarter
  $ 25.55     $ 19.27  
 
Stock Performance Graph. The performance graph below compares total unitholder return on our units, with the total return of the Standard & Poor’s 500 Index, or “S&P 500 Index,” and our Peer Group Index, a weighted composite of five, nine and eight oil and natural gas production publicly traded partnerships for 2009, 2008 and 2007, respectively. For 2011 and 2010, the Peer Group Index was a weighted composite of six natural gas and oil production publicly traded partnerships, which were paying a distribution for all of 2011 and 2010. Total return includes the change in the market price, adjusted for reinvested dividends or distributions, for the period shown on the performance graph and assumes that $100 was invested in VNR at the last reported sale price of units as reported by New York Stock Exchange ($18.94) on October 24, 2007 (the day trading of units commenced), and in the S&P 500 Index and our peer group index on the same date.  The results shown in the graph below are not necessarily indicative of future performance. The following performance graph and related information shall not be deemed “soliciting material” or “filed” with the SEC, nor shall such information be incorporated by reference into any future filing under the Securities Act of 1933 or the Exchange Act, each as amended, except to the extent that we specifically incorporate it by reference into such filing.
 
 
41

 
 
 
 
 
10/24/07
 
12/31/07
 
12/31/08
 
12/31/09
 
12/31/10
 
12/31/11
 
Vanguard Natural Resources, LLC
$
100.00
 
$
84.48
(1)
$
35.37
(1)
$
154.88
(1)
$
226.94
(1)
$
228.13
(1)
Peer Group Index
$
100.00
 
$
90.76
 
$
42.75
 
$
119.50
 
$
155.81
 
$
169.49
 
S&P 500 Index
$
100.00
 
$
96.87
 
$
59.59
 
$
73.56
 
$
82.96
 
$
82.96
 
 
(1)
Based on the last reported sale price of VNR units as reported by New York Stock Exchange on December 31, 2007 ($16.00), 2008 ($5.90), 2009 ($22.07), 2010 ($29.65) and 2011 ($27.63).
 
Distributions Declared. The following table shows the amount per unit, record date and payment date of the quarterly cash distributions we paid on each of our common units for each period presented. Future distributions are at the discretion of our board of directors and will depend on business conditions, earnings, our cash requirements and other relevant factors.
 
   
Cash Distributions
   
Per Unit
 
Record Date
 
Payment Date
2011
           
Fourth Quarter
 
$
0.5875
 
February 7, 2012
 
February 14, 2012
Third Quarter
 
$
0.5775
 
November  7, 2011
 
November 14, 2011
Second Quarter
 
$
0.575
 
August 5, 2011
 
August 12, 2011
First Quarter
 
$
0.570
 
May 6, 2011
 
May 13, 2011
2010
             
Fourth Quarter
 
$
0.560
 
February 7, 2011
 
February 14, 2011
Third Quarter
 
$
0.550
 
November  5, 2010
 
November 12, 2010
Second Quarter
 
$
0.550
 
August 6, 2010
 
August 13, 2010
First Quarter
 
$
0.525
 
May 7, 2010
 
May 14, 2010
 
Our limited liability company agreement requires that, within 45 days after the end of each quarter, we distribute all of our available cash to unitholders of record on the applicable record date. Available cash generally means, for any quarter ending prior to liquidation:
 
 
42

 
 
 
(a)                    the sum of:
 
 
 
(i)
all our and our subsidiaries’ cash and cash equivalents (or our proportionate share of cash and cash equivalents in the case of subsidiaries that are not wholly-owned) on hand at the end of that quarter; and
     
 
(ii)
all our and our subsidiaries’ additional cash and cash equivalents (or our proportionate share of cash and cash equivalents in the case of subsidiaries that are not wholly-owned) on hand on the date of determination of available cash for that quarter resulting from working capital borrowings made subsequent to the end of such quarter,
 
 
 
(b)                   less the amount of any cash reserves established by the board of directors (or our proportionate share of cash and cash equivalents in the case of subsidiaries that are not wholly-owned) to:
 
 
 
(i)
provide for the proper conduct of our or our subsidiaries’ business (including reserves for future capital expenditures, including drilling and acquisitions, and for our and our subsidiaries’ anticipated future credit needs);
     
 
(ii)
comply with applicable law or any loan agreement, security agreement, mortgage, debt instrument or other agreement or obligation to which we or any of our subsidiaries is a party or by which we are bound or our assets are subject; or
     
 
(iii)
provide funds for distributions to our unitholders with respect to any one or more of the next four quarters;
 
 
provided that disbursements made by us or any of our subsidiaries or cash reserves established, increased or reduced after the end of a quarter but on or before the date of determination of available cash for that quarter shall be deemed to have been made, established, increased or reduced, for purposes of determining available cash, within that quarter if the board of directors so determines.

Equity Compensation Plans. See “Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters" for information regarding our equity compensation plans as of December 31, 2011.
 
 
 
Set forth below is our summary of our consolidated financial and operating data for the periods indicated for Vanguard Natural Resources, LLC.

 The selected financial data should be read together with “ Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Item 8. Financial Statements and Supplementary Data” included in this Annual Report.
 
The following table presents a non-GAAP financial measure, adjusted EBITDA, which we use in our business. This measure is not calculated or presented in accordance with GAAP. We explain this measure below and reconcile it to the most directly comparable financial measure calculated and presented in accordance with GAAP in “—Non-GAAP Financial Measure.”

 
43

 
 
Year Ended December 31, (5)
 
 (in thousands, except per unit data)
2011 (6)
   
2010
   
2009
   
2008
   
2007
 
Statement of Operations Data:
                             
Revenues:
                             
Oil, natural gas and NGLs sales
$
312,842
   
$
85,357
   
$
46,035
   
$
68,850
   
$
34,541
 
Gain (loss) on commodity cash flow hedges (1)
 
(3,071
)
   
(2,832
)
   
(2,380
)
   
269
     
(702
)
Realized gain (loss) on other commodity derivative contracts (1)
 
10,276
     
24,774
     
29,993
     
(6,552
)
   
 
Unrealized gain (loss) on other commodity derivative contracts (1)
 
(470
)
   
(14,145
)
   
(19,043
   
39,029
     
 
Total revenues
 
319,577