10-K 1 form10k.htm FORM 10-K form10k.htm


 
 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K
                                                                                                                          (Mark One)

þ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2010
or
o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from _______ to ________

Commission File Number: 001-33676

ENCORE ENERGY PARTNERS LP
(Exact name of registrant as specified in its charter)

Delaware
20-8456807
(State or other jurisdiction
(I.R.S. Employer
of incorporation or organization)
Identification No.)

5847 San Felipe, Suite 3000, Houston, Texas
77057
(Address of principal executive offices)
(Zip Code)

Registrant’s telephone number, including area code:  (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 Representing Limited Partner Interests
New York Stock Exchange
 
 
Securities registered pursuant to Section 12(g) of the Act: None

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

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 þ

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 þ   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 during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o   No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.þ

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 filer o                                           Accelerated filer þ                                           Non-accelerated filer o                                                            Smaller reporting company o
                                                                                                           (Do not check if a smaller reporting company)
 
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes o   No þ

Aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity of the registrant was last sold as of June 30, 2010 (the last business day of the registrant’s most recently completed second fiscal quarter) $415,128,949

Number of Common Units outstanding as of February 28, 2011 45,341,597

DOCUMENTS INCORPORATED BY REFERENCE: None
 
 
 

 
 
 
INDEX

   
 
Page

 
 
 

 
GLOSSARY

The following are abbreviations and definitions of certain terms used in this annual report on Form 10-K (the “Report”):

·  
Bbl.  One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.
·  
Bbl/D.  One Bbl per day.
·  
Bcf. One billion cubic feet, used in reference to natural gas.
·  
Bcfe.  One billion cubic feet of natural gas equivalent, calculated by converting oil to natural gas at a ratio of one Bbl of oil to six Mcf of natural gas.
·  
BOE.  One barrel of oil equivalent, calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Bbl of oil.
·  
BOE/D.  One BOE per day.
·  
CO2.  Carbon dioxide
·  
Completion.  The installation of permanent equipment for the production of oil or natural gas.
·  
Council of Petroleum Accountants Societies (“COPAS”).  A professional organization of oil and natural gas accountants that maintains consistency in accounting procedures and interpretations, including the procedures that are part of most joint operating agreements.  These procedures establish a drilling rate and an overhead rate to reimburse the operator of a well for overhead costs, such as accounting and engineering.
·  
Delay Rentals.  Fees paid to the lessor of an oil and natural gas lease during the primary term of the lease prior to the commencement of production from a well.
·  
Developed Acreage.  The number of acres allocated or assignable to producing wells or wells capable of production.
·  
Development Well.  A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
·  
Dry Hole.  An exploratory, development, or extension well that proves to be incapable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well.
·  
Denbury.  Denbury Resources Inc., a publicly traded Delaware corporation, together with its subsidiaries.
·  
EAC.  Encore Acquisition Company, together with its subsidiaries.  EAC merged with and into Denbury on March 9, 2010.
·  
ENP.  Encore Energy Partners LP, a publicly traded Delaware limited partnership, together with its subsidiaries.
·  
Exploratory Well.  A well drilled to find a new field or to find a new reservoir in a field previously producing oil or natural gas in another reservoir.
·  
Farm-out.  Transfer of all or part of the operating rights from the working interest holder to an assignee, who assumes all or some of the burden of development, in return for an interest in the property.  The assignor usually retains an overriding royalty, but may retain any type of interest.
·  
FASB.  Financial Accounting Standards Board.
·  
FASC.  FASB Accounting Standards Codification.
·  
Field.  An area consisting of a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.
·  
GAAP.  Accounting principles generally accepted in the United States.
·  
Gross Acres or Gross Wells.  The total acres or wells, as the case may be, in which an entity owns a working interest.
·  
Lease Operating Expense (“LOE”).  All direct and allocated indirect costs of producing hydrocarbons after completion of drilling and before commencement of production.  Such costs include labor, superintendence, supplies, repairs, maintenance, and direct overhead charges.
·  
LIBOR.  London Interbank Offered Rate.
·  
MBbl.  One thousand Bbls.
·  
MBOE.  One thousand BOE.
·  
Mcf.  One thousand cubic feet, used in reference to natural gas.
·  
Mcf/D.  One Mcf per day.
·  
MMBbl.  One million Bbls.
·  
MMBOE.  One million BOE.
·  
MMcf.  One million cubic feet, used in reference to natural gas.
·  
MMcf/D.  One MMcf per day.
·  
MMcfe.  One MMcf equivalent, determined by converting oil to natural gas equivalent at a  ratio of one Bbl of oil to six Mcf of natural gas.
·  
MMcfe/D.  One MMcfe per day.
·  
Natural Gas Liquids (“NGLs”).  The combination of ethane, propane, butane, and natural gasolines that when removed from natural gas become liquid under various levels of higher pressure and lower temperature.
·  
Net Acres or Net Wells.  Gross acres or wells, as the case may be, multiplied by the working interest percentage owned by an entity.
·  
Net Profits Interest.  An interest that entitles the owner to a specified share of net profits from the production of hydrocarbons.
·  
NYMEX.  New York Mercantile Exchange.
·  
NYSE.  The New York Stock Exchange.
·  
Oil.  Crude oil, condensate, and NGLs.
·  
Operator.  The entity responsible for the exploration, development, and production of a well or lease.
·  
Present Value of Future Net Revenues (“PV-10”). The present value of estimated future revenues to be generated from the production of proved reserves, net of estimated future production and development costs, using prices and costs as of the date of estimation without future escalation, without giving effect to commodity derivative activities, non-property related expenses such as general and administrative expenses, debt service, depletion, depreciation, and amortization, and income taxes, discounted at an annual rate of 10 percent.
·  
Production costs.  Costs incurred to operate and maintain our wells and related equipment and facilities.  For a complete definition of production costs, please refer to the SEC’s Regulation S-X, Rule 4-10(a)(20).
·  
Production Margin.  Wellhead revenues less production expenses.
· 
Production Taxes.  Production expense attributable to production and severance taxes.
·  
Productive Well.  A well capable of producing hydrocarbons in commercial quantities, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities.
·  
Proved Developed Reserves.  Reserves of any category that can be expected to be recovered: (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well, is acreage that is allocated or assignable to producing wells or wells capable of production. For a complete definition of developed oil and gas reserves, refer to the SEC’s Regulation S-X, Rule 4-10(a)(6).
·  
Proved Reserves.  Those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible — from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations — prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.  For a complete definition of proved oil and gas reserves, refer to the SEC’s Regulation S-X, Rule 4-10(a)(22).
·  
Proved Undeveloped Reserves.  Reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.  For a complete definition of undeveloped oil and gas reserves, refer to the SEC’s Regulation S-X, Rule 4-10(a)(31).
·  
Recompletion.  The completion for production of an existing wellbore in another formation from that in which the well has been previously completed.
·  
Reliable Technology.  A grouping of one or more technologies (including computational methods) that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.
·  
Reserves.  Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to the economically producible, as of a given date, by application of development projects to known accumulations.  In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.
·  
Reservoir.  A porous and permeable underground formation containing a natural accumulation of producible hydrocarbons that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
·  
Royalty.  An interest in an oil and natural gas lease that gives the owner the right to receive a portion of the production from the leased acreage (or of the proceeds from the sale thereof), but does not require the owner to pay any portion of the production or development costs on the leased acreage.  Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.
·  
SEC.  The United States Securities and Exchange Commission.
·  
Secondary Recovery.  Enhanced recovery of hydrocarbons from a reservoir beyond the hydrocarbons that can be recovered by normal flowing and pumping operations.  Involves maintaining or enhancing reservoir pressure by injecting water, gas, or other substances into the formation in order to displace hydrocarbons toward the wellbore.  The most common secondary recovery techniques are gas injection and waterflooding.
·  
Standardized Measure.  Future cash inflows from proved reserves, less future production costs, development costs, net abandonment costs, and income taxes, discounted at 10 percent per annum to reflect the timing of future net cash flows.  Standardized Measure differs from PV-10 because Standardized Measure includes the effect of estimated future net abandonment costs and income taxes.
·  
Tertiary Recovery.  An enhanced recovery operation that normally occurs after waterflooding in which chemicals or natural gases are used as the injectant.
·  
Undeveloped Acreage.  Lease acreage on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil or natural gas regardless of whether such acreage contains proved reserves.
·  
Unit.  A specifically defined area within which acreage is treated as a single consolidated lease for operations and for allocations of costs and benefits without regard to ownership of the acreage.  Units are established for the purpose of recovering hydrocarbons from specified zones or formations.
·  
Vanguard.  Vanguard Natural Resources, LLC, a publicly traded Delaware limited liability company, together with its subsidiaries.
· 
VNG.  Vanguard Natural Gas, LLC, a wholly-owned subsidiary of Vanguard.
·  
Waterflood.  A secondary recovery operation in which water is injected into the producing formation in order to maintain reservoir pressure and force oil toward and into the producing wells.
·  
Working Interest.  An interest in an oil or natural gas lease that gives the owner the right to drill for and produce hydrocarbons on the leased acreage and requires the owner to pay a share of the production and development costs.
·  
Workover.  Operations on a producing well to restore or increase production.
 
 
 
i

 
 

 
As used in this Report, references to “ENP,” “we,” “our,” “us,” or similar terms refer to Encore Energy Partners LP and its subsidiaries, unless the context indicates otherwise.  References to “our general partner” refer to Encore Energy Partners GP LLC, our general partner.  References to “our operating company” and “OLLC” refer to Encore Energy Partners Operating LLC, our operating company.  References to “EAC” refer to Encore Acquisition Company, a former parent company of our general partner, and its subsidiaries.  References to “Denbury” refer to Denbury Resources Inc., a former parent company of our general partner, and its subsidiaries.  References to “Encore Operating” refer to Encore Operating, L.P., a wholly owned subsidiary of Denbury.  References to “Vanguard” refer to Vanguard Natural Resources, LLC, the ultimate parent company of our general partner, and its subsidiaries.  References to “VNG” refer to Vanguard Natural Gas, LLC, a wholly-owned subsidiary of Vanguard.  This Report contains forward-looking statements, which give our current expectations or forecasts of future events.  Please read “Item 1A. Risk Factors” for a description of various factors that could materially affect our ability to achieve the anticipated results described in the forward-looking statements.  Certain terms commonly used in the oil and natural gas industry and in this Report are defined under the caption “Glossary.”  In addition, all production and reserve volumes disclosed in this Report represent amounts net to us, unless otherwise noted.



General

Our Business.  We are a Delaware limited partnership formed in February of 2007 by EAC and are engaged in the acquisition, exploitation, and development of oil and natural gas reserves from onshore fields in the United States.  Our primary business objective is to make quarterly cash distributions to our unitholders in accordance with our guideline as discussed in “Item 7. Management’s Discussion and Analysis of Financial Condition and results of Operations – Capital Commitments, Capital Resources, and Liquidity – Capital commitments – Distributions to unitholders.”  Our properties and oil and natural gas reserves are located in four core areas:

•       the Big Horn Basin in Wyoming and Montana;
•       the Permian Basin in West Texas and New Mexico;
•       the Williston Basin in North Dakota and Montana; and
•       the Arkoma Basin in Arkansas and Oklahoma.
 
On March 9, 2010, EAC, a former parent of our general partner, was merged with and into Denbury (the “Merger”), with Denbury surviving the Merger.  As part of the Merger, Denbury became the then owner of our general partner and approximately 46.1 percent of our outstanding common units.

On November 17, 2010, Denbury announced that it had entered into an agreement to sell its ownership interests in ENP to VNG, the parent of our general partner, for $300 million in cash and approximately 3.14 million Vanguard common units (the “Vanguard Acquisition”).  The transaction closed on December 31, 2010.  Denbury sold its interest in the entity which owns 100 percent of our general partner and approximately 20.9 million of our common units, or approximately 46.1 percent of our outstanding common units.

Proved Reserves.  Our estimated total proved reserves at December 31, 2010 were 28.7 MMBbls of oil and 74.5 Bcf of natural gas, based on 2010 12-month average market prices of $79.43 per Bbl of oil and $4.45 per Mcf of natural gas.  On a BOE basis, our proved reserves were 41.1 MMBOE at December 31, 2010, of which 70 percent was oil, 90 percent was proved developed, and 10 percent was proved undeveloped.

Drilling.  In 2010, we participated in drilling 1 gross (0.1 net) non-operated productive well.  We invested $5.9 million in development and exploitation activities in 2010.

Financial Information About Operating Segments.  We have operations in only one industry segment: the oil and natural gas exploration and production industry in the United States.

 
1

 

Organizational Structure

The following diagram depicts our organizational structure as of February 28, 2011:


 
 
Operations

Well Operations

In general, we seek to be the operator of wells in which we have a working interest.  As operator, we design and manage the development of a well and supervise operation and maintenance activities on a day-to-day basis.  We do not own drilling rigs or other oilfield service equipment used for drilling or maintaining wells on properties we operate.  Independent contractors engaged by us provide all the equipment and personnel associated with these activities.

As of December 31, 2010, we operated properties representing approximately 86 percent of our proved reserves.  As the operator, we are able to better control expenses, capital allocation, and the timing of exploitation and development activities on our properties.  We also own working interests in properties that are operated by third parties for which we are required to pay our share of production, exploitation, and development costs.  Please read “— Properties — Nature of Our Ownership Interests.”  During 2010, 2009, and 2008, our development costs on non-operated properties were approximately 31 percent, 66 percent, and 24 percent, respectively, of our total development costs.  We also own royalty interests in wells operated by third parties that are not burdened by production or capital costs; however, we have little or no control over the implementation of projects on these properties.

 
2

 
We do not have any employees.  The employees supporting our operations were: the employees of EAC prior to March 2010, the employees of Denbury from March 2010 to December 31, 2010, and became the employees of VNG pursuant to the Vanguard Acquisition on December 31, 2010.  During 2010, Encore Operating provided administrative services for us, such as accounting, corporate development, finance, land, legal, and engineering pursuant to an administrative services agreement.  In addition, Encore Operating provided all personnel, facilities, goods, and equipment necessary to perform these services which are not otherwise provided for by us.  Encore Operating was not liable to us for its performance of, or failure to perform, services under the administrative services agreement unless its acts or omissions constitute gross negligence or willful misconduct.  On December 31, 2010, duties under the administrative services agreement were assigned to VNG pursuant to the Vanguard Acquisition.

Encore Operating initially received an administrative fee of $1.75 per BOE of our production for such services.  From April 1, 2008 to March 31, 2009, the administrative fee was $1.88 per BOE of our production.  From April 1, 2009 to March 31, 2010, the administrative fee was $2.02 per BOE of our production.  Effective April 1, 2010, the administrative fee was increased to $2.06 per BOE of our production.  We also reimbursed Encore Operating for actual third-party expenses incurred on our behalf.  In addition, Encore Operating was entitled to retain any COPAS overhead charges associated with drilling and operating wells that would otherwise be paid by non-operating interest owners to the operator.  Pursuant to the Vanguard Acquisition, VNG will receive the fees and reimbursements for services performed in 2011.

The administrative fee will increase in the following circumstances:

·  
beginning on the first day of April in each year by an amount equal to the product of the then-current administrative fee multiplied by the COPAS Wage Index Adjustment for that year;
·  
if we acquire any additional assets, VNG may propose an increase in its administrative fee that covers the provision of services for such additional assets; however, such proposal must be approved by the board of directors of our general partner upon the recommendation of its conflicts committee; and
·  
otherwise as agreed upon by VNG and our general partner, with the approval of the conflicts committee of the board of directors of our general partner.

Natural Gas Gathering

We own and operate a network of natural gas gathering systems in our 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 our 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.

Our gas gathering systems were operated for us by Encore Operating during 2010 pursuant to the administrative services agreement.  During 2011, VNG will operate our gas gathering systems pursuant to the administrative services agreement.

Seasonal Nature of Business

Oil and natural gas producing operations are generally not seasonal.  However, demand for some of our products can fluctuate season to season, which impacts price.  In particular, heavy oil is typically in higher demand in the summer for its use in road construction, and natural gas is generally in higher demand in the winter for heating.

 
3

 
Production and Price History

The following table sets forth information regarding our production volumes, average realized prices, and average costs per BOE for the periods indicated:

   
Year Ended December 31,
 
   
2010
   
2009
   
2008
 
 Total Production Volumes:
                 
    Oil (MBbls)
    2,227       2,364       2,534  
    Natural gas (MMcf)
    5,836       6,097       6,219  
    Combined (MBOE)
    3,200       3,380       3,571  
 Average Daily Production Volumes:
                       
    Oil (Bbl/D)
    6,101       6,476       6,925  
    Natural gas (Mcf/D)
    15,990       16,703       16,991  
    Combined (BOE/D)
    8,766       9,259       9,757  
 Average Realized Prices:
                       
    Oil (per Bbl)
  $ 69.77     $ 54.33     $ 89.55  
    Natural gas (per Mcf)
    4.82       3.55       8.76  
    Combined (per BOE)
    57.34       44.39       78.81  
 Average Costs per BOE:
                       
    Lease operating
  $ 13.45     $ 12.86     $ 13.10  
    Production taxes and marketing
    5.69       4.87       9.41  
    Depletion, depreciation, and amortization
    15.81       17.01       16.26  
    Exploration
    0.06       0.93       0.05  
    Derivative fair value loss (gain)
    4.42       14.04       (27.13 )
    General and administrative
    3.87       3.56       4.65  


Productive Wells

The following table sets forth information relating to the productive wells in which we owned a working interest as of December 31, 2010.  Wells are classified as oil or natural gas wells according to their predominant production stream.  We also hold royalty interests in units and acreage beyond the wells in which we have a working interest.
 
   
Oil Wells
   
Natural Gas Wells
 
               
Average
               
Average
 
   
Gross
   
Net
   
Working
   
Gross
   
Net
   
Working
 
   
Wells (a)
   
Wells
   
Interest
   
Wells (a)
   
Wells
   
Interest
 
 Big Horn Basin
    353       272       77 %     41       30       73 %
 Williston Basin
    106       70       66 %     23       6       26 %
 Permian Basin
    1,542       379       25 %     562       274       49 %
 Arkoma Basin
    9       1       11 %     129       10       8 %
            Total
    2,010       722       36 %     755       320       42 %
_____________
(a)  
Our total wells include 1,112 operated wells and 1,653 non-operated wells.  At December 31, 2010, 35 of our wells had multiple completions.

Acreage

The following table sets forth information relating to our leasehold acreage at December 31, 2010.  Developed acreage is assigned to productive wells.  Undeveloped acreage is acreage held under lease, permit, contract, or option that is not in a spacing unit for a producing well, including leasehold interests identified for exploitation or exploratory drilling.  As of December 31, 2010, our undeveloped acreage in the Williston Basin represented approximately 60 percent of our total net undeveloped acreage.  All of our oil and natural gas leases are held by production, which means that for as long as our wells continue to produce oil or natural gas, we will continue to own the lease.

 
4

 
 
   
Gross Acreage
   
Net Acreage
 
 Big Horn Basin:
           
    Developed
    23,392       19,327  
    Undeveloped
    1,120       1,073  
      24,512       20,400  
 Williston Basin:
               
    Developed
    39,870       31,689  
    Undeveloped
    9,859       6,595  
      49,729       38,284  
 Permian Basin:
               
    Developed
    59,617       37,612  
    Undeveloped
    4,036       5,099  
      63,653       42,711  
 Arkoma Basin:
               
    Developed
    3,192       411  
    Undeveloped
    357       84  
      3,549       495  
                 
 Total:
               
    Developed
    126,071       89,039  
    Undeveloped
    15,372       12,851  
      141,443       101,890  
 
Development Results

We concentrate our development activity and production optimization projects on lower risk, development projects.  The number and types of wells we drill or projects we undertake vary depending on the amount of funds we have available, the cost of those activities, the size of the fractional working interest we acquire in each well, and the estimated recoverable reserves attributable to each well.

The following table sets forth information with respect to wells completed during the periods indicated, regardless of when development was initiated.  This information should not be considered indicative of future performance, nor should a correlation be assumed between productive wells drilled, quantities of reserves discovered, or economic value.

   
Year Ended December 31,
 
   
2010
   
2009
   
2008
 
   
Gross
   
Net
   
Gross
   
Net
   
Gross
   
Net
 
 Development Wells:
                                   
    Productive
    1       0.1       9       1.2       49       15.3  
    Dry holes
    -       -       -       -       -       -  
      1       0.1       9       1.2       49       15.3  
 Exploratory Wells:
                                               
    Productive
    -       -       6       0.6       10       1.3  
    Dry holes
    -       -       1       1.0       1       -  
      -       -       7       1.6       11       1.3  
 Total:
                                               
    Productive
    1       0.1       15       1.8       59       16.6  
    Dry holes
    -       -       1       1.0       1       -  
      1       0.1       16       2.8       60       16.6  
 
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 have terms of one year or less.  As of December 31, 2010, we do not have any ongoing delivery commitments.

 
5

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

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

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 accurately predict future crude oil and natural gas differentials.  Adverse changes in the differential between the NYMEX price for oil and natural gas and the wellhead price we receive could have a material adverse effect on our results of operations, financial position, cash flows, and ability to make distributions.  The following table shows the relationship between oil and natural gas wellhead prices as a percentage of average NYMEX prices by quarter for 2010:
 
   
First Quarter
   
Second Quarter
   
Third Quarter
   
Fourth Quarter
 
   
of 2010
   
of 2010
   
of 2010
   
of 2010
 
Average oil wellhead to NYMEX percentage
    91 %     88 %     86 %     86 %
Average natural gas wellhead to NYMEX percentage
    113 %     99 %     106 %     119 %
 
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 2010 increased to a level above NYMEX with the exception of the second quarter of 2010.

Principal Customers

For 2010, our largest purchaser was Marathon Oil Corporation, which accounted for 30 percent of our total sales of production.  Our marketing of oil and natural gas can be affected by factors beyond our control, the potential effects of which cannot be accurately predicted.  To the extent these and other customers reduce the volumes of natural gas, NGLs, and oil that they purchase from us and they are not replaced in a timely manner with a new customer, our revenues and cash available for distribution could decline.  However, if we were to lose a customer, we believe we could identify a substitute purchaser in a timely manner.

Competition

The oil and natural gas industry is highly competitive.  We encounter strong competition from other oil companies in acquiring properties.  Many of these competitors have resources substantially larger than ours.  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 resources will permit.

We are also affected by competition for rigs and the availability of related equipment.  The oil and natural gas industry has experienced shortages of rigs, equipment, pipe, and personnel, which has delayed development and exploitation activities and has caused significant price increases.  We are unable to predict when, or if, such shortages may occur or how they would affect our development and exploitation program.

 
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Competition is also strong for attractive oil and natural gas producing properties, undeveloped leases, and development rights, and we may not be able to compete satisfactorily when attempting to acquire additional properties.

Properties

Nature of Our Ownership Interests

The following table sets forth the production, average wellhead prices, and average LOE per BOE of our properties by principal area of operation for the periods indicated:
 
 
   
Production
         
Average
       
         
Natural
         
Percent
   
Average Oil
   
Natural Gas
   
Lease
 
   
Oil
   
Gas
   
Total
   
of Total
   
Wellhead
   
Wellhead
   
Operating
 
   
(MBbls)
   
(MMcf)
   
(MBOE)
         
(per Bbl)
   
(per Mcf)
   
(per BOE)
 
 2010
                                         
 Big Horn Basin
    1,347       340       1,404       44 %   $ 69.04     $ 1.17     $ 12.49  
 Williston Basin
    392       281       438       14 %     68.46       5.16       16.85  
 Arkoma Basin
    25       843       166       5 %     65.04       4.20       1.90  
 Permian Basin
    463       4,372       1,192       37 %     73.24       5.20       14.92  
           Total
    2,227       5,836       3,200       100 %     69.77       4.82       13.45  
 2009
                                                       
 Big Horn Basin
    1,422       337       1,478       44 %     54.33       0.94       12.82  
 Williston Basin
    414       291       463       14 %     53.23       3.68       17.59  
 Arkoma Basin
    24       963       185       5 %     49.66       2.75       1.95  
 Permian Basin
    504       4,506       1,254       37 %     55.42       3.91       12.77  
           Total
    2,364       6,097       3,380       100 %     54.33       3.55       12.86  
 2008
                                                       
 Big Horn Basin
    1,517       365       1,578       44 %     86.22       3.70       13.54  
 Williston Basin
    459       345       516       14 %     91.26       9.16       14.54  
 Arkoma Basin
    16       986       181       5 %     97.65       7.53       1.15  
 Permian Basin
    542       4,523       1,296       36 %     97.21       9.40       13.64  
           Total
    2,534       6,219       3,571       100 %     89.55       8.76       13.10  
 
 
The following table sets forth the proved reserves of our properties by principal area of operation as of December 31, 2010:

         
Natural
         
Percent
 
   
Oil
   
Gas
   
Total
   
of Total
 
   
(MBbls)
   
(MMcf)
   
(MBOE)
       
 Proved Developed:
                       
    Big Horn Basin
    16,682       2,208       17,050       46 %
    Williston Basin
    3,961       2,695       4,410       12 %
    Arkoma Basin
    192       7,345       1,416       4 %
    Permian Basin
    4,980       54,750       14,105       38 %
       Total Proved Developed
    25,815       66,998       36,981       100 %
 Proved Undeveloped:
                               
    Big Horn Basin
    1,284       -       1,284       31 %
    Williston Basin
    505       251       547       13 %
    Permian Basin
    1,049       7,278       2,262       55 %
       Total Proved Undeveloped
    2,838       7,529       4,093       100 %
 Total Proved:
                               
    Big Horn Basin
    17,966       2,208       18,334       45 %
    Williston Basin
    4,466       2,946       4,957       12 %
    Arkoma Basin
    192       7,345       1,416       4 %
    Permian Basin
    6,029       62,028       16,367       40 %
       Total Proved
    28,653       74,527       41,074       100 %
 
 
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The following table sets forth the PV-10 of our properties by principal area of operation as of December 31, 2010:
 
   
Amount (a)
   
Percent of Total
 
   
(in thousands)
       
 Big Horn Basin
  $ 413,309       59 %
 Williston Basin
    94,623       13 %
 Arkoma Basin
    18,472       3 %
 Permian Basin
    177,126       25 %
           Total
  $ 703,530       100 %
________
 
(a)
Giving effect to commodity derivative contracts, our PV-10 would decrease by $14.9 million at December 31, 2010.  Standardized Measure at December 31, 2010 was $695.6 million.  Standardized Measure differs from PV-10 by approximately $7.9 million because Standardized Measure includes the effect of future net abandonment costs and future income taxes.  Since we are taxed as a partnership that is not subject to federal income taxes, future income taxes reflect the impact of estimated future Texas margin taxes in the Permian Basin area.

Proved Reserves
 
SEC Rule-Making Activity.  In December 2008, the SEC announced that it had approved revisions designed to modernize the oil and gas company reserves reporting requirements.  These revisions were effective for reserve determinations as of December 31, 2009.  Pursuant to the SEC’s final rule, prior period reserves were not restated.  The SEC’s rules expanded the technologies that a company can use to establish reserves.  The SEC allows use of techniques that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty.  We used a combination of drilling results, production and pressure performance, wireline wellbore measurements, simulation studies, offset analogies, seismic data and interpretation, wireline formation tests, geophysical logs, and core data to calculate our reserves estimates, including the material additions to the 2010 reserves estimates.

Proved Undeveloped Reserves (“PUDs”).  As of December 31, 2010, our PUDs totaled 2.8 MMBbls of crude oil and 7.5 Bcf of natural gas, for a total of 4.1 MMBOE or about 10 percent of our total proved reserves.  During 2010, we added 450 MMBOE of PUDs as a result of revisions.
 
All of our PUDs as of December 31, 2010 are associated with development projects that are scheduled to begin drilling within the next 5 years.  Our major development areas are located in our West Texas and Big Horn fields.  All of these projects will convert to proved developed reserves as, and to the extent, these projects achieve production response.

Internal Controls Over Reserves Estimates.  Our policies regarding internal controls over the recording of reserves estimates requires reserves to be in compliance with the SEC definitions, rules, and regulations and guidance and prepared in accordance with the February 19, 2007 publication of the Society of Petroleum Engineers (“SPE”) entitled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” (“SPE 2007 Standards”).  For 2010, we engaged an independent petroleum engineering consulting firm, DeGolyer and MacNaughton (“D&M”), to prepare our reserve estimates.  The technical persons responsible for preparing the reserves estimates presented herein meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth by the SPE in the SPE 2007 Standards.
 
Our general partner maintains an internal staff of petroleum engineers who work closely with D&M to ensure the integrity, accuracy, and timeliness of data furnished to D&M in their reserves estimation process.  In the fourth quarter, our general partner’s technical team meets 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.  While our general partner has no formal committee specifically designated to review reserves reporting and the reserves estimation process, the D&M reserve report is reviewed by our general partner’s senior management and internal technical staff.  Additionally, our general partner’s senior management reviews and approves any internally estimated significant changes to our proved reserves on a quarterly basis.

Rules and regulations established by the SEC were used to prepare these reserve estimates.  Oil and natural gas reserve engineering is and must be recognized as a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in any exact way, and estimates of other engineers might differ materially from those included herein.  The accuracy of any reserve estimate is a function of the quality of available data and engineering, and estimates may justify revisions based on the results of drilling, testing, and production activities.  Accordingly, reserve estimates and their PV-10 are inherently imprecise, subject to change, and should not be construed as representing the actual quantities of future production or cash flows to be realized from oil and natural gas properties or the fair market value of such properties.

 
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Other Reserve Information.  During 2010, we filed the estimates of our oil and natural gas reserves as of December 31, 2009 with the U.S. Department of Energy on Form EIA-23.  As required by Form EIA-23, the filing reflected only gross production that comes from our operated wells at year-end.  Those estimates came directly from our reserve report prepared by Miller and Lents, Ltd., which was the independent petroleum engineering consulting firm engaged to assist us at that time.

 
 
Big Horn Basin Properties

Our Big Horn Basin properties, which include the Elk Basin properties and the Gooseberry field, are located in northwestern Wyoming and south central Montana.  The Big Horn Basin is characterized by oil and natural gas fields with long production histories and multiple producing formations.  The Big Horn Basin is a prolific basin and has produced over 1.8 billion Bbls of oil since its discovery in 1906.

During 2010, production from our Big Horn Basin properties averaged approximately 3,847 BOE/D, of which approximately 96 percent was oil.  Our Big Horn Basin properties had estimated proved reserves at December 31, 2010 of 18.3 MMBOE, of which 17.2 MMBOE were proved developed and 1.3 MMBOE were proved undeveloped.

 
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Elk Basin Properties

Our properties in the Elk Basin area are located in the Elk Basin field, Northwest Elk Basin field, and the South Elk Basin field.  The major producing horizons in these fields are the Embar-Tensleep, Madison, Frontier, and Big Horn formations.  The Elk Basin assets had estimated proved reserves at December 31, 2010 of 13.8 MMBOE, of which 12.5 MMBOE were proved developed and 1.3 MMBOE were proved undeveloped.  Our properties in the Elk Basin area include 17,075 gross acres (13,349 net) located in Park County, Wyoming and Carbon County, Montana.  All of our production in the Elk Basin area is operated.

We also own and operate (1) the Elk Basin natural gas processing plant near Powell, Wyoming, (2) the Clearfork crude oil pipeline extending from the South Elk Basin field to the Elk Basin field in Wyoming, (3) the Wildhorse natural gas gathering system that transports low sulfur natural gas from the Elk Basin and South Elk Basin fields to our Elk Basin natural gas processing plant, and (4) a small natural gas gathering system that transports high sulfur natural gas from the Elk Basin field to our Elk Basin natural gas processing facility.

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.  We hold an average 62 percent working interest and an average 56 percent net revenue interest in these wells.  At December 31, 2010, the Embar-Tensleep formation had estimated total proved reserves of 5.4 MMBOE, all of which were oil and 95 percent of which were proved developed.

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

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

Other Oil and Natural Gas Properties.  We also operate wells in the Northwest Elk Basin field and South Elk Basin field.  We hold an average 65 percent working interest and an average 68 percent net revenue interest in our wells in these fields.  The Northwest Elk Basin field and South Elk Basin field had estimated total proved reserves at December 31, 2010 of 477 MBOE, 65 percent of which were oil and all of which were proved developed.

Natural Gas Processing Plant.  We operate and own a 62 percent interest in the Elk Basin natural gas processing plant near Powell, Wyoming, which was first placed into operation in the 1940s.  ExxonMobil Corporation owns a 34 percent interest in the Elk Basin natural gas processing plant, and other parties own the remaining 4 percent interest.

The Elk Basin natural gas processing plant is a refrigeration natural gas processing plant that receives natural gas supplies through a natural gas gathering system from fields in the Elk Basin and South Elk Basin fields.  During 2010, the Elk Basin natural gas processing plant produced approximately 380 net Bbls of NGLs per day consisting primarily of propane, normal butane, and natural gasoline.

Pipelines.  We own and operate one crude oil pipeline system and two natural gas gathering pipeline systems.  The Clearfork pipeline is regulated by the FERC and transports approximately 4,369 Bbls/D of crude oil from the Elk Basin field to a pipeline operated by Marathon Oil Corporation for further delivery to other markets.  Most of the crude oil transported by the Clearfork pipeline is eventually sold to refineries in Billings, Montana.  The Clearfork pipeline receives crude oil from various interconnections with local gathering systems.

 
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The Wildhorse pipeline system is an approximately 12-mile natural gas gathering system that transports approximately 1.3 MMcf/D of low-sulfur natural gas from the Elk Basin and South Elk Basin fields to our Elk Basin natural gas processing plant.  The natural gas transported by the Wildhorse gathering system is sold into the WBI Pipeline.

We also own a small natural gas gathering system that transports approximately 14.0 MMcf/D of high sulfur natural gas from the Elk Basin field to our Elk Basin natural gas processing plant.

Gooseberry Field

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

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 2010, production from our Williston Basin properties averaged approximately 1,200 BOE/D, of which approximately 89 percent was oil.  Our Williston Basin properties had estimated proved reserves at December 31, 2010 of 5.0 MMBOE, of which 4.4 MMBOE were proved developed and 0.5 MMBOE were proved undeveloped.
 
Permian Basin Properties

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

For 2010, production from our Permian Basin properties was approximately 19,596 MMcfe/D, 61 percent of which was natural gas.  Our Permian Basin properties had estimated proved reserves at December 31, 2010 of 98.2 Bcfe, of which 84.6 Bcfe were proved developed and 13.6 Bcfe were proved undeveloped.  As of December 31, 2010, our Permian Basin properties consisted of 63,653 gross (42,711 net) acres.

Operated Properties. In West Texas, we operate 646 wells in eight areas: Crockett, Dune, Sand Hills, Champmon, Nolley/McFarland, Hutex, Slaughter/Levelland, and Vinegarone.  We operate 5 wells in the Brunson area of New Mexico.

The Crockett area is located in Crockett County, Texas.  Producing fields include Angus, Henderson, Hunt-Baggett, and Ozona.  These wells are primarily gas wells completed in the Canyon Sand and Strawn formations.  The productive intervals are tight sand deposits at 6,500 to 8,500 feet of depth.  The Vinegarone field is located in ValVerde County, Texas.  These gas wells produce from the Strawn reservoir.

There are two fields located in Crane County, Texas.  The Dune field is a waterflood property producing from the San Andres formation.  The Sand Hills field has production in the waterflooded Tubb formation as well as production from the Wojcik-McElroy, McKnight, Judkins, Clearfork, and Penn formations.

The Champmon field is located on a Strawn reef structure in Gaines County, Texas.  The field was discovered in 1996 and is drilled on 40-acre spacing.  Three fields are located in Andrews County, Texas.  The Nolley-McFarland area consists of two fields – Nolley and McFarland.  Production is primarily oil from wells completed in the Queen, Clearfork, Wolfcamp, and Penn formations.  Depths range from 4,500 to 10,500 feet.  The Hutex field produces from the Strawn, Dean, and Devonian formations.  The Slaughter and Levelland fields are located in Cochran County, Texas.  Production is primarily oil from the San Andres.  The waterflood operations in these fields have been ongoing since the 1970s.
 
 
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The wells in New Mexico Brunson area produce from multiple formations which are downhole commingled.  The formations include Blinebry, Drinkard, Tubb, and Wantz.

Non-Operated Properties. We own non-operated interests in several fields in the Permian Basin.  The largest are the North Cowden field and the Crockett area fields.  We also own interests in the Yates field in Pecos County as well as interests in Loco Hills field in Eddy County, New Mexico.

The North Cowden field is a legacy West Texas field located in Ector County, Texas.  The North Cowden field has been undergoing secondary waterflood operations since the 1970s.  More recently, the field has successfully piloted CO2 injection as a tertiary method for recovering additional oil.

The Crockett area includes fields in the Davidson Ranch, Hunt-Baggett, Live Oak Draw, and Ozona fields in Crockett County, Texas.  At December 31, 2010, we held an average working interest of 21 percent and an average net revenue interest of 15 percent in the producing wells developed in this area.  These wells produce from the Canyon Sand and Strawn formations at depths of 8,000 to 9,000 feet.  Many of the wells were not completed in all of the known producing intervals.

The Canyon Sand formation in Crockett County is drilled to 40-acre spacing, and many of our non-operated leases have drilling locations remaining to be developed.  We have identified 13.6 Bcfe of proved undeveloped reserves on these properties.

Our properties in Crockett County are operated by several companies, but a majority of the wells are operated by a private oil and gas company that has drilled over 80 wells in Crockett County, Texas since 2000.  Until 2010, we historically participated with this company in drilling 2 to 4 wells per year.

Arkoma Properties

Our Arkoma properties include royalty interests and non-operated working interest properties.  The royalty interest properties include interests in over 1,700 wells in Arkansas, Texas, and Oklahoma as well as 10,300 unleased mineral acres.  The non-operated working interest properties include interests in over 100 producing wells in the Chismville field.  At December 31, 2010, the properties had total proved reserves of approximately 8.5 Bcfe, all of which were proved developed and 87 percent of which were natural gas.  During 2010, the production from our Arkoma properties averaged approximately 2,724 MMcfe/D, of which 85 percent was natural gas.  During 2010, we participated in drilling 1 gross (0.1 net) non-operated well in our Arkoma area.

Title to Properties

We believe that we have satisfactory title to our oil and natural gas properties in accordance with standards generally accepted in the oil and natural gas industry.

Our properties are subject, in one degree or another, to one or more of the following:

·  
royalties, overriding royalties, and other burdens under oil and natural gas leases;
·  
contractual obligations, including, in some cases, development obligations arising under operating agreements, farm-out agreements, production sales contracts, and other agreements that may affect the properties or their titles;
·  
liens that arise in the normal course of operations, such as those for unpaid taxes, statutory liens securing unpaid suppliers and contractors, and contractual liens under operating agreements;
·  
pooling, unitization, and communitization agreements, declarations, and orders; and
·  
easements, restrictions, rights-of-way, and other matters that commonly affect property.

We believe that the burdens and obligations affecting our properties do not, in the aggregate, materially interfere with the use of the properties.

We have granted mortgage liens on substantially all of our oil and natural gas properties in favor of Bank of America, N.A., as agent, to secure borrowings under our revolving credit facility.  These mortgages and the revolving credit facility contain substantial restrictions and operating covenants that are customarily found in loan agreements of this type.

 
12

 

Environmental Matters and Regulation

General.  Our operations are subject to stringent and complex federal, state, and local laws and regulations governing environmental protection, including air emissions, water quality, wastewater discharges, and solid waste management.  These laws and regulations may, among other things:

·  
require the acquisition of various permits before development commences;
·  
require the installation of pollution control equipment;
·  
enjoin some or all of the operations of facilities deemed in non-compliance with permits;
·  
restrict the types, quantities, and concentration of various substances that can be released into the environment in connection with oil and natural gas development, production, and transportation activities;
·  
restrict the way in which wastes are handled and disposed;
·  
limit or prohibit development activities on certain lands lying within wilderness, wetlands, areas inhabited by threatened or endangered species, and other protected areas;
·  
require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells;
·  
impose substantial liabilities for pollution resulting from operations; and
·  
require preparation of a Resource Management Plan, an Environmental Assessment, and/or an Environmental Impact Statement for operations affecting federal lands or leases.

These laws, rules, and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible.  The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability.  Additionally, Congress and federal and state agencies frequently revise environmental laws and regulations, and the clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment.  Any changes that result in indirect compliance costs or additional operating restrictions, including costly waste handling, disposal, and cleanup requirements for the oil and natural gas industry could have a significant impact on our operating costs.

The following is a discussion of relevant environmental and safety laws and regulations that relate to our operations.

Waste Handling.  The Resource Conservation and Recovery Act (“RCRA”), and comparable state statutes, regulate the generation, transportation, treatment, storage, disposal, and cleanup of hazardous and non-hazardous solid wastes.  Under the auspices of the federal Environmental Protection Agency (the “EPA”), the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements.  Drilling fluids, produced waters, and most of the other wastes associated with the exploration, development, and production of crude oil or natural gas are regulated under RCRA’s non-hazardous waste provisions.  However, it is possible that certain oil and natural gas exploration and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future.  Any such change could result in an increase in our costs to manage and dispose of wastes, which could have a material adverse effect on our results of operations and financial position.  Also, in the course of our operations, we generate some amounts of ordinary industrial wastes, such as paint wastes, waste solvents, and waste oils that may be regulated as hazardous wastes.

Site Remediation.  The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the Superfund law, imposes joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment.  These persons include the current and past owner or operator of the site where the release occurred, and anyone who disposed of or arranged for the disposal of a hazardous substance released at the site.  Under CERCLA, such persons may be subject to joint and several liability 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.  CERCLA authorizes the EPA, and in some cases third parties, to take actions in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur.  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.

We own, lease, or operate numerous properties that have been used for oil and natural gas exploration and production for many years.  Although petroleum, including crude oil and natural gas are excluded from CERCLA’s definition of “hazardous substance,” in the course of our ordinary operations, we generate wastes that may fall within the definition of a “hazardous substance.”  We believe that we have utilized operating and waste disposal practices that were standard in the industry at the time, yet hazardous substances, wastes, or 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 such substances have been taken for disposal.  In addition, some of our 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.  In fact, there is evidence that petroleum spills or releases have occurred in the past at some of the properties owned or leased by us.  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.

 
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Our Elk Basin assets have been used for oil and natural gas exploration and production for many years.  There have been known releases of hazardous substances, wastes, or hydrocarbons at the properties, and some of these sites are undergoing active remediation.  The risks associated with these environmental conditions, and the cost of remediation, were assumed by us, subject only to limited indemnity from the seller of the Elk Basin assets.  Releases may also have occurred in the past that have not yet been discovered, which could require costly future remediation.  In addition, we assumed the risk of various other unknown or unasserted liabilities associated with the Elk Basin assets that relate to events that occurred prior to our acquisition.  If a significant release or event occurred in the past, the liability for which was not retained by the seller or for which indemnification from the seller is not available, it could adversely affect our results of operations, financial position, cash flows, and ability to make distributions.

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 contamination, the extent of the 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 contamination even while the gas plant remains in operation.  As of December 31, 2010, we have recorded $5.1 million as future abandonment liability for the estimated cost for decommissioning the Elk Basin natural gas processing plant.  Due to the significant uncertainty associated with the known and unknown environmental liabilities at the gas plant, our estimate of the future abandonment liability includes a large contingency.  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 Clean Water Act (“CWA”), and analogous state laws, impose strict controls on the discharge of pollutants, including spills and leaks of oil and other substances, into 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 the EPA or an analogous state agency.  CWA regulates storm water run-off from oil and natural gas facilities and requires a storm water discharge permit for certain activities.  Such a permit requires the regulated facility to monitor and sample storm water run-off from its operations.  CWA and regulations implemented thereunder also prohibit discharges of dredged and fill material in wetlands and other waters of the United States unless authorized by an appropriately issued permit.  Spill prevention, control, and countermeasure requirements of CWA require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture, or leak.  Federal and state regulatory agencies can impose administrative, civil, and criminal penalties for non-compliance with discharge permits or other requirements of CWA and analogous state laws and regulations.

The primary federal law for oil spill liability is the Oil Pollution Act (“OPA”), which addresses three principal areas of oil pollution—prevention, containment, and cleanup.  OPA applies to vessels, offshore facilities, and onshore facilities, including exploration and production facilities that may affect waters of the United States.  Under OPA, responsible parties, including owners and operators of onshore facilities, may be subject to oil cleanup costs and natural resource damages as well as a variety of public and private damages that may result from oil spills.

Air Emissions.  Oil and natural gas exploration and production operations are subject to the federal Clean Air Act (“CAA”), and comparable state laws and regulations.  These laws and regulations regulate emissions of air pollutants from various industrial sources, including oil and natural gas exploration and production facilities, and also impose various monitoring and reporting requirements.  Such laws and regulations may require a facility to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in the increase of existing air emissions, obtain and strictly comply with air permits containing various emissions and operational limitations, or utilize specific emission control technologies to limit emissions.

 
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Permits and related compliance obligations under CAA, as well as changes to state implementation plans for controlling air emissions in regional non-attainment areas, may require oil and natural gas exploration and production operations to incur future capital expenditures in connection with the addition or modification of existing air emission control equipment and strategies.  In addition, some oil and natural gas facilities may be included within the categories of hazardous air pollutant sources, which are subject to increasing regulation under CAA.  Failure to comply with these requirements could subject a regulated entity to monetary penalties, injunctions, conditions or restrictions on operations, and enforcement actions.  Oil and natural gas exploration and production facilities may be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions.

Scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases” and including carbon dioxide and methane, may be contributing to warming of the atmosphere.  In response to such studies, Congress is considering legislation to reduce emissions of greenhouse gases.  In addition, at least 17 states have declined to wait on Congress to develop and implement climate control legislation and have already taken legal measures to reduce emissions of greenhouse gases.  Also, as a result of the Supreme Court’s decision on April 2, 2007 in Massachusetts, et al. v. EPA, the EPA must consider whether it is required to regulate greenhouse gas emissions from mobile sources (e.g., cars and trucks) even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases.  The Supreme Court’s holding in Massachusetts that greenhouse gases fall under CAA’s definition of “air pollutant” may also result in future regulation of greenhouse gas emissions from stationary sources under various CAA programs, including those used in oil and natural gas exploration and production operations.  It is not possible to predict how legislation that may be enacted to address greenhouse gas emissions would impact the oil and natural gas exploration and production business.  However, future laws and regulations could result in increased compliance costs or additional operating restrictions and could have a material adverse effect on our business, financial condition, demand for our operations, results of operations, cash flows, and ability to make distributions.

Activities on Federal Lands.  Oil and natural gas exploration and production activities on federal lands are subject to the National Environmental Policy Act (“NEPA”).  NEPA requires federal agencies, including the Department of the Interior, to evaluate major agency actions having the potential to significantly impact the environment.  In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses 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 exploration and production activities and planned exploration and development activities on federal lands require governmental permits that are subject to the requirements of NEPA.  This process has the potential to delay the development of our oil and natural gas projects.

Occupational Safety and Health Act (“OSH Act”) and Other Laws and Regulation.  We are subject to the requirements of OSH Act and comparable state statutes.  These laws and the implementing regulations strictly govern the protection of the health and safety of employees.  The Occupational Safety and Health Administration’s hazard communication standard, EPA community right-to-know regulations under Title III of CERCLA, and similar state statutes require that we organize and/or disclose information about hazardous materials used or produced in our operations.  We believe that we are in substantial compliance with these applicable requirements and with other OSH Act and comparable requirements.

We believe that we are in substantial compliance with all existing environmental laws and regulations applicable to our operations and that our continued compliance with existing requirements will not have a material adverse impact on our financial condition and results of operations.  We did not incur any material capital expenditures for remediation or pollution control activities during 2010, and, as of the date of this Report, we are not aware of any environmental issues or claims that will require material capital expenditures in the future.  However, accidental spills or releases may occur in the course of our operations, and we may incur substantial costs and liabilities as a result of such spills or releases, including those relating to claims for damage to property and persons.  Moreover, the passage of more stringent laws or regulations in the future may have a negative impact on our business, financial condition, results of operations, or ability to make distributions.

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.

 
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Legislation continues to be introduced in Congress and development of regulations continues in the Department of Homeland Security and other agencies concerning the security of industrial facilities, including oil and natural gas facilities.  Our operations may be subject to such laws and regulations.  Presently, it is not possible to accurately estimate the costs we could incur to comply with any such facility security laws or regulations, but such expenditures could be substantial.

Development 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 development of wells, development bonds, and reports concerning operations.  Most states, and some counties and municipalities, in which we operate also regulate one or more of the following:

· location of wells;
· methods of developing and casing wells;
· surface use and restoration of properties upon which wells are drilled;
· plugging and abandoning of wells; and
· notification of surface owners and other third parties.

State laws regulate the size and shape of development and spacing units or proration units governing the pooling of oil and natural gas properties.  Some states allow forced pooling or integration of tracts in order 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 and natural gas 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.

Natural Gas Gathering.  Section 1(b) of the Natural Gas Act (“NGA”) exempts natural gas gathering facilities from the jurisdiction of the Federal Energy Regulatory Commission (the “FERC”).  We own a number of facilities that we believe would meet the traditional tests the FERC has used to establish a pipeline’s status as a gatherer not subject to the FERC’s jurisdiction.  In the states in which we operate, regulation of gathering facilities and intrastate pipeline facilities generally includes various safety, environmental, and in some circumstances, nondiscriminatory take requirement and complaint-based rate regulation.

Natural gas gathering may receive greater regulatory scrutiny at both the state and federal levels since the FERC has taken a less stringent approach to regulation of the offshore gathering activities of interstate pipeline transmission companies and a number of such companies have transferred gathering facilities to unregulated affiliates.  Our gathering operations could be adversely affected should they become subject to the application of state or federal regulation of rates and services.  Our gathering operations also may be or become subject to safety and operational regulations relating to the design, installation, testing, construction, operation, replacement, and management of gathering facilities.  Additional rules and legislation pertaining to these matters are considered or adopted from time to time.  We cannot predict what effect, if any, such changes might have on our operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.

Sales of Natural Gas.  The price at which we buy and sell natural gas is not subject to federal regulation and, for the most part, is not subject to state regulation.  Our sales of natural gas are affected by the availability, terms, and cost of pipeline transportation.  The price and terms of access to pipeline transportation are subject to extensive federal and state regulation.  The FERC is continually proposing and implementing new rules and regulations affecting those segments of the natural gas industry, most notably interstate natural gas transmission companies that remain subject to the FERC’s jurisdiction.  These initiatives also may affect the intrastate transportation of natural gas under certain circumstances.  The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry, and these initiatives generally reflect more light-handed regulation.  We cannot predict the ultimate impact of these regulatory changes on our natural gas marketing operations, and we note that some of the FERC’s more recent proposals may adversely affect the availability and reliability of interruptible transportation service on interstate pipelines.  We do not believe that we will be affected by any such FERC action materially differently than other natural gas marketers with which we compete.

The Energy Policy Act of 2005 (“EP Act 2005”) gave the FERC increased oversight and penalty authority regarding market manipulation and enforcement.  EP Act 2005 amended NGA to prohibit market manipulation and also amended NGA and the Natural Gas Policy Act of 1978 (“NGPA”) to increase civil and criminal penalties for any violations of NGA, NGPA, and any rules, regulations, or orders of the FERC to up to $1,000,000 per day, per violation.  In 2006, the FERC issued a rule regarding market manipulation, which makes it unlawful for any entity, in connection with the purchase or sale of natural gas or transportation service subject to the FERC’s jurisdiction, to defraud, make an untrue statement, or omit a material fact, or engage in any practice, act, or course of business that operates or would operate as a fraud.  This rule works together with the FERC’s enhanced penalty authority to provide increased oversight of the natural gas marketplace.

 
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State Regulation.  The various states regulate the development, production, gathering, and sale of oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits.  Reduced rates or credits may apply to certain types of wells and production methods.

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.

States also regulate the method of developing new fields, the spacing and operation of wells, and the prevention of waste of oil and natural gas resources.  States may regulate rates of production and establish maximum daily production allowables from oil and natural gas wells based on market demand or resource conservation, or both.  States do not regulate wellhead prices or engage in other similar direct economic regulation, but they may do so in the future.  The effect of these regulations may be to limit the amounts of oil and natural gas that may be produced from our wells, and to limit the number of wells or locations we can drill.

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,  The Bureau of Ocean Energy Management, Regulation and Enforcement, 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

The officers of our general partner manage our operations and activities.  However, neither we nor our general partner have employees.  During 2010, Encore Operating provided administrative services for us pursuant to an administrative services agreement.  For additional information regarding the administrative services agreement, please read “Administrative Services Agreement” included in “Item 13.  Certain Relationships and Related Transactions, and Director Independence.”

Following the Vanguard Acquisition, Vanguard had a staff of 68 persons, including 3 engineers, none of which are represented by labor unions or covered by any collective bargaining agreement.  We believe that Vanguard’s relations with its employees are satisfactory.
 
Principal Executive Office

Our principal executive office is located at 5847 San Felipe, Suite 3000, Houston, Texas 77057.  Our main telephone number is (832) 327-2255.

 
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Available Information

We make available electronically, free of charge through our website (www.encoreenp.com), our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and other filings with the SEC pursuant to Section 13(a) of the Securities Exchange Act of 1934 (the “Exchange Act”) as soon as reasonably practicable after we electronically file such material with, or furnish such material to, the SEC.  In addition, you may read and copy any materials that we file with the SEC at its public reference room at 100 F Street, NE, Room 1580, Washington, DC 20549.  Information concerning the operation of the public reference room may be obtained by calling the SEC at 1-800-SEC-0330.  The SEC also maintains a website (www.sec.gov) that contains reports, proxy statements, and other information regarding issuers, like us, that file electronically with the SEC.

We have adopted a code of business conduct and ethics that applies to all directors, officers, and employees of our general partner, including the principal executive officer and principal financial officer of our general partner.  The code of business conduct and ethics is available on our website.  In the event that we make changes in, or provide waivers from, the provisions of this code of business conduct and ethics that the SEC or the NYSE requires us to disclose, we intend to disclose these events on our website.

The board of directors of our general partner has two standing committees: (1) audit and (2) conflicts.  The NYSE does not require a listed limited partnership like us to have a majority of independent directors on the board of directors of our general partner or to establish a compensation committee or a nominating and corporate governance committee.  The audit committee charter, our code of business conduct and ethics, and our corporate governance guidelines are available on our website.

The information on our website or any other website is not incorporated by reference into this Report.


You should carefully consider each of the following risks and all of the information provided elsewhere in this Report.  If any of the risks described below or elsewhere in this Report were actually to occur, our business, financial condition, results of operations, or cash flows could be materially and adversely affected.  In that case, we may be unable to pay distributions on our common units, the trading price of our common units could decline, and you could lose all or part of your investment.

Risks Related to Our Business

We may not have sufficient cash flow from operations to pay quarterly distributions on our common units following establishment of cash reserves and payment of fees and expenses, including reimbursement of expenses to our general partner and VNG.

We may not have sufficient available cash each quarter to pay quarterly distributions.  Under the terms of our partnership agreement, the amount of cash otherwise available for distribution is reduced by our operating expenses and the amount of any cash reserves that our general partner establishes to provide for future operations, capital expenditures, acquisitions of oil and natural gas properties, debt service requirements, and cash distributions to our unitholders.

The amount of cash we actually generate depends upon numerous factors related to our business that may be beyond our control, including, among other things, the risks described in this section.  In addition, the actual amount of cash that we have available for distribution depends on other factors, including:

·  
our capital expenditures;
·  
our ability to make borrowings under our revolving credit facility to pay distributions;
·  
sources of cash used to fund acquisitions;
·  
debt service requirements and restrictions on distributions contained in our revolving credit facility or future debt agreements;
·  
fluctuations in our working capital needs;
·  
general and administrative expenses;
·  
cash settlements of commodity derivative contracts;
·  
timing and collectibility of receivables; and
·  
the amount of cash reserves established by our general partner for the proper conduct of our business.

Our oil and natural gas reserves naturally decline, and we will be unable to sustain distributions at the current level without making accretive acquisitions or substantial capital expenditures that maintain or grow our asset base.

 
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Because our oil and natural gas properties are a depleting asset, our future oil and natural gas reserves, production volumes, cash flow, and ability to make distributions depend on our success in developing and exploiting our current reserves efficiently and finding or acquiring additional recoverable reserves economically.  We may not be able to develop, find, or acquire additional reserves to replace our current and future production at acceptable costs, which would adversely affect our business, financial condition, and results of operations and reduce cash available for distribution.

We need to make substantial capital expenditures to maintain and grow our asset base, which reduce our cash available for distribution.  Because the timing and amount of these capital expenditures fluctuate each quarter, we expect to reserve substantial amounts of cash each quarter to finance these expenditures over time.  We may use the reserved cash to reduce indebtedness until we make the capital expenditures.  Over a longer period of time, if we do not set aside sufficient cash reserves or make sufficient expenditures to maintain our asset base, we will be unable to pay distributions at the current level from cash generated from operations and would therefore expect to reduce our distributions.

If our reserves decrease and we do not reduce our distribution, then a portion of the distribution may be considered a return of part of our unitholders’ investment in us as opposed to a return on investment.  Also, if we do not make sufficient capital expenditures, we will be unable to expand our business operations and will therefore be unable to raise future distributions.

To fund our capital expenditures, we must use cash generated from our operations, additional borrowings, or the issuance of additional equity or debt securities, or some combination thereof, which would limit our ability to pay distributions at the then-current distribution rate.

The use of cash generated from operations to fund capital expenditures reduces cash available for distribution to our unitholders.  Our ability to obtain financing or to access the capital markets for future equity or debt offerings may be limited by our financial condition at the time of any such financing or offering and the covenants in our existing debt agreements, as well as by adverse market conditions resulting from, among other things, general economic conditions, and contingencies and uncertainties that are beyond our control.  Our failure to obtain the funds for necessary future capital expenditures could have a material adverse effect on our business, results of operations, financial condition, and ability to pay distributions.  Even if we are successful in obtaining the necessary funds, the terms of such financings could limit our ability to pay distributions to our unitholders.  In addition, incurring additional debt may significantly increase our interest expense and financial leverage, and issuing additional partnership interests may result in significant unitholder dilution, thereby increasing the aggregate amount of cash required to maintain the then-current distribution rate, which could limit our ability to pay distributions at the then-current distribution rate.

We may not make cash distributions during periods when we record net income.

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

Oil and natural gas prices are very volatile.  A decline in commodity prices could materially and adversely affect our financial condition, results of operations, liquidity, and cash flows, which may force us to reduce our distributions or cease paying distributions altogether.

The oil and natural gas markets are very volatile, and we cannot accurately predict future oil and natural gas prices.  Prices for oil and natural gas may fluctuate widely in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty, and a variety of additional factors that are beyond our control, such as:

·  
overall domestic and global economic conditions;
·  
weather conditions;
·  
political and economic conditions in oil and natural gas producing countries, including those in the Middle East, Africa, and South America;
·  
actions of the Organization of Petroleum Exporting Countries and state-controlled oil companies relating to oil price and production controls;
·  
the impact of U.S. dollar exchange rates on oil and natural gas prices;
·  
technological advances affecting energy consumption and energy supply;
·  
domestic and foreign governmental regulations and taxation;
·  
the impact of energy conservation efforts;
·  
the proximity, capacity, cost, and availability of oil and natural gas pipelines and other transportation facilities;
·  
the availability of refining capacity; and
·  
the price and availability of alternative fuels.
 
 
 
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The worldwide financial and credit crisis reduced the availability of liquidity and credit to fund the continuation and expansion of industrial business operations worldwide.  The shortage of liquidity and credit combined with substantial losses in worldwide equity markets led to an extended worldwide economic slowdown.  The slowdown in economic activity reduced worldwide demand for energy and resulted in lower oil and natural gas prices.

Our revenue, profitability, and cash flow depend upon the prices of and demand for oil and natural gas, and a drop in prices can significantly affect our financial results and impede our growth.  In particular, declines in commodity prices will:

·  
negatively impact the value of our reserves, because declines in oil and natural gas prices would reduce the amount of oil and natural gas that we can produce economically;
·  
reduce the amount of cash flow available for capital expenditures, repayment of indebtedness, and other corporate purposes;
·  
result in a decrease in the borrowing base under our revolving credit facility or otherwise limit our ability to borrow money or raise additional capital; and
·  
impair our ability to pay distributions.

If we raise our distribution levels in response to increased cash flow during periods of relatively high commodity prices, we may not be able to sustain those distribution levels during periods of low commodity prices.

An increase in the differential between benchmark prices of oil and natural gas and the wellhead price we receive could adversely affect our financial condition, results of operations, and cash flows, which could significantly reduce our cash available for distribution.

The prices that we receive for our oil and natural gas production sometimes trade at a discount to the relevant benchmark prices, such as NYMEX.  The difference between the benchmark price and the price we receive is called a differential.  We cannot accurately predict oil and natural gas differentials.  For example, the oil production from our Big Horn Basin assets has historically sold at a higher discount to NYMEX as compared to our Permian Basin assets due to competition from Canadian and Rocky Mountain producers, in conjunction with limited refining and pipeline capacity from the Rocky Mountain area, and corresponding deep pricing discounts by regional refiners.  Increases in differentials could significantly reduce our cash available for distribution and adversely affect our financial condition and results of operations.

Price declines may result in a write-down of our asset carrying values, which could have a material adverse effect on our results of operations and limit our ability to borrow funds under our revolving credit facility and make distributions.

Declines in oil and natural gas prices may result in our having to make substantial downward revisions to our estimated reserves.  If this occurs, or if our estimates of development costs increase, production data factors change, or development results deteriorate, 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 incur such impairment charges, it could have a material adverse effect on our results of operations in the period incurred and on our ability to borrow funds under our revolving credit facility, which in turn may adversely affect our ability to make cash distributions to our unitholders.  In addition, any write-downs that result in a reduction in our borrowing base could require prepayments of indebtedness under our revolving credit facility.

Our commodity derivative contract activities could result in financial losses or could reduce our income and cash flows, which may adversely affect our ability to pay distributions to our unitholders.  Furthermore, in the future, our commodity derivative contract positions may not adequately protect us from changes in commodity prices.

To achieve more predictable cash flow and to reduce our exposure to fluctuations in the price of oil and natural gas, we enter into derivative arrangements for a significant portion of our forecasted oil and natural gas production.  The extent of our commodity price exposure is related largely to the effectiveness and scope of our derivative activities, as well as to the ability of counterparties under our commodity derivative contracts to satisfy their obligations to us.  For example, the derivative instruments we utilize are based on posted market prices, which may differ significantly from the actual prices we realize in our operations.  Changes in oil and natural gas prices could result in losses under our commodity derivative contracts.

 
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Our actual future production may be significantly higher or lower than we estimate at the time we enter into derivative transactions for such period.  If the actual amount is higher than we estimate, we will have greater commodity price exposure than we intended.  If the actual amount is lower than the notional amount of 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 the sale of the underlying physical commodity, resulting in a substantial diminution of our liquidity.  As a result of these factors, our derivative 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 derivative activities are subject to the following risks:

·  
a counterparty may not perform its obligation under the applicable derivative instrument, which risk may have been exacerbated by the worldwide financial and credit crisis; and
·  
there may be a change in the expected differential between the underlying commodity price in the derivative instrument and the actual price received, which may result in payments to our derivative counterparty that are not accompanied by our receipt of higher prices from our production in the field.

In addition, certain commodity derivative contracts that we may enter into may limit our ability to realize additional revenues from increases in the prices for oil and natural gas.

We have oil and natural gas commodity derivative contracts covering a significant portion of our forecasted production through 2014.  These contracts are intended to reduce our exposure to fluctuations in the price of oil and natural gas.  After 2014, and unless we enter into new commodity derivative contracts, our exposure to oil and natural gas price volatility will increase significantly each year as our commodity derivative contracts expire.  We may not be able to obtain additional commodity derivative contracts on acceptable terms, if at all.  Our failure to mitigate our exposure to commodity price volatility through commodity derivative contracts could have a negative effect on our financial condition and results of operation and significantly reduce our cash flows.

The counterparties to our derivative contracts may not be able to perform their obligations to us, which could materially affect our cash flows, results of operations, and ability to make distributions.

As of December 31, 2010, we were entitled to future payments of approximately $15.7 million from counterparties under our commodity derivative contracts.  The worldwide financial and credit crisis may have adversely affected the ability of these counterparties to fulfill their obligations to us.  If one or more of our counterparties is unable or unwilling to make required payments to us under our commodity derivative contracts, it could have a material adverse effect on our financial condition, results of operations, and ability to make distributions.

Our estimated proved 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.

It is not possible to measure underground accumulations of oil or natural gas in an exact way.  In estimating our oil and natural gas reserves, we and our independent petroleum engineers make certain assumptions that may prove to be incorrect, including assumptions relating to oil and natural gas prices, production levels, capital expenditures, operating and development costs, the effects of regulation, and availability of funds.  If these assumptions prove to be incorrect, our estimates of reserves, the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, the classification of reserves based on risk of recovery, and our estimates of the future net cash flows from our reserves could change significantly.

Our Standardized Measure is calculated using prices and costs in effect as of the date of estimation, less future development, production, net abandonment, and income tax expenses, and discounted at 10 percent per annum to reflect the timing of future net revenue in accordance with the rules and regulations of the SEC.  The Standardized Measure of our estimated 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 estimated proved reserves on prices and costs in effect on the day of estimate.  Over time, we may make material changes to reserve estimates to take into account changes in our assumptions and the results of actual development and production.

 
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The reserve estimates we make for fields that do not have a lengthy production history are less reliable than estimates for fields with lengthy production histories.  A lack of production history may contribute to inaccuracy in our estimates of proved reserves, future production rates, and the timing of development expenditures.

The timing of both our production and our incurrence of expenses in connection with the development, production, and abandonment 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 percent 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.

Developing and producing oil and natural gas are costly and 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.

The cost of developing, completing, and operating a well is often uncertain, and cost factors can adversely affect the economics of a well.  If commodity prices decline, the cost of developing, completing and operating a well may not decline in proportion to the prices that we receive for our production, resulting in higher operating and capital costs as a percentage of oil and natural gas revenues.  Our efforts will be uneconomical if we drill dry holes or wells that are productive but do not produce as much oil and natural gas as we had estimated.  Furthermore, our development and production operations may be curtailed, delayed, or canceled as a result of other factors, including:

·  
higher costs, shortages of, or delivery delays of rigs, equipment, labor, or other services;
·  
unexpected operational events and/or conditions;
·  
reductions in oil and natural gas prices;
·  
increases in severance taxes;
·  
limitations in the market for oil and natural gas;
·  
adverse weather conditions and natural disasters;
·  
facility or equipment malfunctions, and equipment failures or accidents;
·  
title problems;
·  
pipe or cement failures and casing collapses;
·  
compliance with environmental and other governmental requirements;
·  
environmental hazards, such as natural gas leaks, oil spills, pipeline ruptures, and discharges of toxic gases;
·  
lost or damaged oilfield development and service tools;
·  
unusual or unexpected geological formations, and pressure or irregularities in formations;
·  
loss of drilling fluid circulation;
·  
fires, blowouts, surface craterings, and explosions;
·  
uncontrollable flows of oil, natural gas, or well fluids; and
·  
loss of leases due to incorrect payment of royalties.

If any of these factors were to occur with respect to a particular field, we could lose all or a part of our investment in the field, or we could fail to realize the expected benefits from the field, either of which could materially and adversely affect our revenue and profitability and, as a result, our ability to pay distributions to our unitholders.

Secondary and tertiary recovery techniques may not be successful, which could adversely affect our financial condition or results of operations and, as a result, our ability to pay distributions to our unitholders.

A significant portion of our production and reserves rely on secondary and tertiary recovery techniques.  If production response is less than forecasted for a particular project, then the project may be uneconomic or generate less cash flow and reserves than we had estimated prior to investing capital.  Risks associated with secondary and tertiary recovery techniques include, but are not limited to, the following:

·  
lower than expected production;
·  
longer response times;
·  
higher operating and capital costs;
·  
shortages of equipment; and
·  
lack of technical expertise.

 
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If any of these risks occur, it could adversely affect our financial condition or results of operations and, as a result, our ability to pay distributions to our unitholders.

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

Higher oil and natural gas prices generally increase the demand for rigs, equipment, and crews and can lead to shortages of, and increasing costs for, development equipment, services, and personnel.  Shortages of, or increasing costs for, experienced development crews and oil field equipment and services could restrict our ability to drill the wells and conduct the operations that we have planned.  Any delay in the development of new wells or a significant increase in development costs could reduce our revenues and as a result, our cash available for distribution.

If we do not make acquisitions, our future growth, and ability to pay or increase distributions could be limited.

Acquisitions are an essential part of our growth strategy, and our ability to grow and to increase distributions to unitholders depends in part on our ability to make acquisitions that result in an increase in pro forma available cash per unit.  We may be unable to make such acquisitions because we are:

·  
unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them;
·  
unable to obtain financing for these acquisitions on economically acceptable terms; or
·  
outbid by competitors.

Competition for acquisitions is intense and may increase the cost of, or cause us to refrain from, completing acquisitions.  If we are unable to acquire properties with proved reserves, our total proved reserves could decline as a result of our production, and we will be limited in our ability to increase or possibly even to maintain our level of cash distributions.  Future acquisitions could result in our incurring additional debt, contingent liabilities, and expenses, all of which could have a material adverse effect on our financial condition and results of operations.  Furthermore, our financial position and results of operations may fluctuate significantly from period to period based on whether significant acquisitions are completed in particular periods.

Any acquisitions we complete are subject to substantial risks that could adversely affect our financial condition and results of operations and reduce our ability to make distributions to unitholders.

Even if we complete acquisitions that we believe will increase pro forma available cash per unit, these acquisitions may nevertheless result in a decrease in pro forma available cash per unit.  Any acquisition involves potential risks, including, among other things:

·  
the validity of our assumptions about reserves, future production, revenues, capital expenditures, and operating costs, including synergies;
·  
an inability to integrate the businesses we acquire successfully;
·  
a decrease in our liquidity by using a significant portion of our available cash or borrowing capacity under our revolving credit facility 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 from other business concerns;
·  
natural disasters;
·  
the incurrence of other significant charges, such as impairment of oil and natural gas properties, goodwill, or other intangible assets, asset devaluation, or restructuring charges;
·  
unforeseen difficulties encountered in operating in new geographic areas; 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.

 
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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 given time constraints imposed by sellers.  Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to fully assess their deficiencies and potential.  Inspections may not always be performed on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken.

Due to our lack of asset and geographic diversification, adverse developments in our operating areas would negatively affect our financial condition and results of operations and reduce our ability to make distributions to our unitholders.

We only own oil and natural gas properties and related assets.  All of our assets are located in Wyoming, Montana, North Dakota, Arkansas, Texas, Oklahoma, and New Mexico.  Due to our lack of diversification in asset type and location, an adverse development in the oil and natural gas business in these geographic areas would have a significantly greater impact on our results of operations and cash available for distribution to our unitholders than if we maintained more diverse assets and locations.

We depend on certain customers for a substantial portion of our sales.  If these customers reduce the volumes of oil and natural gas they purchase from us, our revenues and cash available for distribution will decline to the extent we are not able to find new customers for our production.

For 2010, our largest purchaser was Marathon Oil Corporation, which accounted for 30 percent of our total sales of production.  If this customer, or any other significant customer, were to reduce the production purchased from us, our revenue and cash available for distribution will decline to the extent we are not able to find new customers for our production.

Competition in the oil and natural gas industry is intense and 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 with respect to acquiring prospects and productive properties, marketing oil and natural gas, and securing equipment and trained personnel, and we compete with other companies that have greater resources.  Many of our competitors are major and large independent oil and natural gas companies, and possess financial and technical resources substantially greater than us.  Those companies may be able to develop and acquire more prospects and productive properties than our resources permit.  Our ability to acquire additional properties and to discover reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment.  Some of our competitors not only drill for and produce oil and natural gas 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 resources permit.  In addition, there is substantial competition for investment capital in the oil and natural gas industry.  These companies may have a greater ability to continue development activities during periods of low oil and natural gas prices and to absorb the burden of present and future federal, state, local, and other laws and regulations.  Our inability to compete effectively could have a material adverse impact on our business activities, financial condition, and results of operations.

We may incur substantial additional debt to enable us to pay our quarterly distributions, which may negatively affect our ability to execute our business plan and pay future distributions.

We may be unable to pay a distribution at the current distribution rate or a future distribution rate without borrowing under our revolving credit facility.  When we borrow to pay distributions, we are distributing more cash than we are generating from our operations.  This means that we are using a portion of our borrowing capacity under our revolving credit facility to pay distributions rather than to maintain or expand our operations.  If we use borrowings under our revolving 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 units and will have a material adverse effect on our business, financial condition, and results of operations.  If we borrow to pay distributions during periods of low commodity prices and commodity prices remain low, we may have to reduce our distribution in order to avoid excessive leverage.

Our debt levels may limit our flexibility to obtain additional financing and pursue other business opportunities.

 
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As of February 18, 2011, we had $240 million of outstanding borrowings and $135 million of borrowing capacity under our revolving credit facility.  We have the ability to incur additional debt under our revolving credit facility, subject to borrowing base limitations.  Our future indebtedness could have important consequences to us, including:

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

Our ability to service our indebtedness depends upon, among other things, our future financial and operating performance, which is affected by prevailing economic conditions and financial, business, regulatory, and other factors, some of which are beyond our control.  If our operating results are not sufficient to service our indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying business activities, acquisitions, investments and/or capital expenditures, selling assets, restructuring or refinancing our indebtedness, or seeking additional equity capital or bankruptcy protection.  We may not be able to effect any of these remedies on satisfactory terms or at all.

In addition, we are not currently permitted to offset the value of our commodity derivative contracts with a counterparty against amounts that may be owed to such counterparty under our revolving credit facilities.

Our revolving credit facility has substantial restrictions and financial covenants that may restrict our business and financing activities and our ability to pay distributions.

The operating and financial restrictions and covenants in our revolving credit facility and any future financing agreements may restrict our ability to finance future operations or capital needs or to engage, expand, or pursue our business activities or to pay distributions.

Our ability to comply with the restrictions and covenants in our revolving credit facility in the future is uncertain and will be affected by the levels of cash flow from our operations and events or circumstances beyond our control.  If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired.  If we violate any of the restrictions, covenants, or financial ratios in our revolving credit facility, a significant portion of our indebtedness may become immediately due and payable, our ability to make distributions will be inhibited, and our lenders’ commitment to make further loans to us may terminate.  We might not have, or be able to obtain, sufficient funds to make these accelerated payments.  In addition, obligations under our revolving credit facility are secured by substantially all of our assets, and if we are unable to repay our indebtedness under our revolving credit facility, the lenders could seek to foreclose on our assets.

Our revolving credit facility limits the amounts we can borrow to a borrowing base amount, determined by the lenders in their sole discretion.  Outstanding borrowings in excess of the borrowing base will be required to be repaid immediately, or we will be required to pledge other oil and natural gas properties as additional collateral.

Possible regulations related to global warming and climate change could have an adverse effect on our operations and the demand for oil and natural gas.

Recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases,” may be contributing to the warming of the Earth’s atmosphere.  Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of refined oil products and natural gas, are examples of greenhouse gases.  The U.S. Congress is considering climate-related legislation to reduce emissions of greenhouse gases.  In addition, at least 20 states have developed measures to regulate emissions of greenhouse gases, primarily through the planned development of greenhouse gas emissions inventories and/or regional greenhouse gas cap and trade programs.  The EPA has adopted regulations requiring reporting of greenhouse gas emissions from certain facilities and is considering additional regulation of greenhouse gases as “air pollutants” under the CAA.  Passage of climate change legislation or other regulatory initiatives by Congress or various states, or the adoption of regulations by the EPA or analogous state agencies, that regulate or restrict emissions of greenhouse gases (including methane or carbon dioxide) in areas in which we conduct business could have an adverse effect our operations and the demand for oil and natural gas.

 
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Our operations are subject to operational hazards and unforeseen interruptions for which we may not be adequately insured.

There are a variety of operating risks inherent in our wells, gathering systems, pipelines, and other facilities, such as leaks, explosions, mechanical problems, and natural disasters, all of which could cause substantial financial losses.  Any of these or other similar occurrences could result in the disruption of our operations, substantial repair costs, personal injury or loss of human life, significant damage to property, environmental pollution, impairment of our operations, and substantial revenue losses.  The location of our wells, gathering systems, pipelines, and other facilities near populated areas, including residential areas, commercial business centers, and industrial sites, could significantly increase the damages resulting from these risks.

We are not fully insured against all risks, including development and completion risks that are generally not recoverable from third parties or insurance.  In addition, pollution and environmental risks generally are not fully insurable.  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.  Moreover, insurance may not be available in the future at commercially reasonable costs and on commercially reasonable terms.  Losses and liabilities from uninsured and underinsured events and delay in the payment of insurance proceeds could have a material adverse effect on our business, financial condition, results of operations, and ability to make distributions to our unitholders.

Our business depends in part on gathering and transportation facilities owned by others.  Any limitation in the availability of those facilities could interfere with our ability to market our oil and natural gas production and could harm our business.

The marketability of our oil and natural gas production depends in part on the availability, proximity, and capacity of pipelines, oil and natural gas gathering systems, and processing facilities.  The amount of oil and 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, or lack of available 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.  Any significant curtailment in gathering system or pipeline capacity could reduce our ability to market our oil and natural gas production and harm our business.

We have limited control over the activities on properties we do not operate.

Other companies operated approximately 14 percent of our properties (measured by total reserves) and approximately 60 percent of our wells as of December 31, 2010.  We have limited ability to influence or control the operation or future development of these non-operated properties or the amount of capital expenditures that we are required to fund with respect to them.  Our dependence on the operator and other working interest owners for these projects and our limited ability to influence or control the operation and future development of these properties could materially adversely affect the realization of our targeted returns on capital in development or acquisition activities and lead to unexpected future costs.

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

Our oil and natural gas exploration and production operations are subject to complex and stringent laws and regulations.  Environmental and other governmental laws and regulations have increased the costs to plan, design, drill, install, operate, and abandon oil and natural gas wells and related pipeline and processing facilities.  In order to conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals, and certificates from various federal, state, and local governmental authorities.  We may incur substantial costs in order to maintain compliance with these existing laws and regulations.  In addition, our costs of compliance may increase if existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations.

Our business is subject to federal, state, and local laws and regulations as interpreted and enforced by governmental authorities possessing jurisdiction over various aspects of the exploration for, and production of, oil and natural gas.  Failure to comply with such laws and regulations, as interpreted and enforced, could have a material adverse effect on our business, financial condition, results of operations, and ability to make distributions to unitholders.  Please read “Items 1 and 2. Business and Properties – Environmental Matters and Regulation” and “Items 1 and 2. Business and Properties – Other Regulation of the Oil and Natural Gas Industry” for a description of the laws and regulations that affect us.
 
 
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Our operations expose us to significant costs and liabilities with respect to environmental and operational safety matters.

We may incur significant costs and liabilities as a result of environmental and safety requirements applicable to our oil and natural gas production activities.  In addition, we often indemnify sellers of oil and natural gas properties for environmental liabilities they or their predecessors may have created.  These costs and liabilities could arise under a wide range of federal, state, and local environmental and safety laws and regulations, which have become increasingly strict over time.  Failure to comply with these laws and regulations may result in the assessment of administrative, civil, and criminal penalties, imposition of cleanup and site restoration costs, liens and, to a lesser extent, issuance of injunctions to limit or cease operations.  In addition, claims for damages to persons or property may result from environmental and other impacts of our operations.

Strict, joint, and several liability may be imposed under certain environmental laws, which could cause us to become liable for the conduct of others or for consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken.  New laws, regulations, or enforcement policies could be more stringent and impose unforeseen liabilities or significantly increase compliance costs.  If we are not able to recover the resulting costs through insurance or increased revenues, our profitability and our ability to make distributions to unitholders could be adversely affected.

Our development and exploratory drilling efforts may not be profitable or achieve our targeted returns.

Development and exploratory drilling and production activities are subject to many risks, including the risk that we will not discover commercially productive oil or natural gas reserves.  In order to further our development efforts, we acquire both producing and unproved properties as well as lease undeveloped acreage that we believe will enhance our growth potential and increase our earnings over time.  However, we cannot assure you that all prospects will be economically viable or that we will not be required to impair our initial investments.

In addition, there can be no assurance that unproved property acquired by us or undeveloped acreage leased by us will be profitably developed, that new wells drilled by us will be productive, or that we will recover all or any portion of our investment in such unproved property or wells.  The costs of drilling and completing wells are often uncertain, and drilling operations may be curtailed, delayed, or canceled as a result of a variety of factors, including unexpected drilling conditions, pressure or irregularities in formations, equipment failures or accidents, weather conditions, and shortages or delays in the delivery of equipment.  Drilling for oil and natural gas may involve unprofitable efforts, not only from dry holes, but also from wells that are productive but do not produce sufficient commercial quantities to cover the development, operating, and other costs.  In addition, wells that are profitable may not meet our internal return targets, which are dependent upon the current and future market prices for oil and natural gas, costs associated with producing oil and natural gas, and our ability to add reserves at an acceptable cost.

Seismic technology does not allow us to obtain conclusive evidence that oil or natural gas reserves are present or economically producible prior to spudding a well.  We rely to a significant extent on seismic data and other advanced technologies in identifying unproved property prospects and in conducting our exploration activities.  The use of seismic data and other technologies also requires greater up-front costs than development on proved properties.

Our development and exploitation operations require substantial capital, and we may be unable to obtain needed financing on satisfactory terms.

We make and will continue to make substantial capital expenditures in development and exploitation projects.  We intend to finance these capital expenditures through operating cash flows.  However, additional financing sources may be required in the future to fund our capital expenditures.  Financing may not continue to be available under existing or new financing arrangements, or on acceptable terms, if at all.  If additional capital resources are not available, we may be forced to curtail our development and other activities or be forced to sell some of our assets on an untimely or unfavorable basis.

 
27

 

Risks Inherent in an Investment in Us

Our general partner and its affiliates own a controlling interest in us and may have conflicts of interest with us and limited fiduciary duties to us, which may permit them to favor their own interests to the detriment of unitholders.

As of February 28, 2011, Vanguard owned approximately 46.1 percent of our outstanding common units and controlled our general partner, which controls us.  The directors and officers of our general partner have a fiduciary duty to manage our general partner in a manner beneficial to Vanguard.  Furthermore, certain directors and officers of our general partner are directors and officers of affiliates of our general partner, including Vanguard.  Conflicts of interest may arise between Vanguard and its affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand.  As a result of these conflicts, our general partner may favor its own interests and the interests of its affiliates over the interests of our unitholders.  These potential conflicts include, among others, the following situations:

·  
neither our partnership agreement nor any other agreement requires Vanguard or its affiliates (other than our general partner) to pursue a business strategy that favors us.  Vanguard’s directors and officers have a fiduciary duty to make these decisions in the best interests of its shareholders, which may be contrary to our interests;
·  
our general partner is allowed to take into account the interests of parties other than us, such as Vanguard and its affiliates, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to our unitholders;
·  
Vanguard is not limited in its ability to compete with us and is under no obligation to offer to sell assets to us;
·  
under the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, does not apply to our general partner or its affiliates (including Vanguard) and no such person who acquires knowledge of a potential transaction, agreement, arrangement, or other matter that may be an opportunity for our partnership will have any duty to communicate or offer such opportunity to us;
·  
the officers of our general partner who provide services to us will devote time to affiliates of our general partner and may be compensated for services rendered to such affiliates;
·  
our general partner has limited its liability, reduced its fiduciary duties, and restricted the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty.  Unitholders are deemed to have consented to some actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable law;
·  
our general partner determines the amount and timing of asset purchases and sales, borrowings, issuance of additional partnership securities, and cash reserves, each of which can affect the amount of cash that is distributed to unitholders;
·  
VNG performs administrative services for us pursuant to an administrative services agreement under which it receives an administrative fee of $2.06 per BOE of our production for such services and reimbursement of actual third-party expenses incurred on our behalf.  VNG has substantial discretion in determining which third-party expenses to incur on our behalf.  In addition, VNG is entitled to retain any COPAS overhead charges associated with drilling and operating wells that would otherwise be paid by non-operating interest owners to the operator of a well;
·  
our general partner may cause us to borrow funds in order to permit the payment of cash distributions;
·  
our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf;
·  
our general partner has limited its liability regarding our contractual and other obligations and, in some circumstances, is entitled to be indemnified by us;
·  
our general partner may exercise its limited right to call and purchase common units if it and its affiliates own more than 80 percent of our common units;
·  
our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates; and
·  
our general partner decides whether to retain separate counsel, accountants, or others to perform services for us.

Vanguard, as the owner of our general partner, has the power to appoint and remove our directors and management.

Since an affiliate of Vanguard owns our general partner, it has the ability to elect all the members of the board of directors of our general partner.  Our general partner has control over all decisions related to our operations.  Since Vanguard also owned approximately 46.1 percent of our outstanding common units as of February 28, 2011, the public unitholders do not have the ability to influence any operating decisions and are not able to prevent us from entering into most transactions.  Furthermore, the goals and objectives of Vanguard and our general partner relating to us may not be consistent with those of a majority of the public unitholders.

 
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We do not have any employees and rely solely on officers of our general partner and employees of Vanguard.  Failure of such officers and employees to devote sufficient attention to the management and operation of our business may adversely affect our financial results and our ability to make distributions to our unitholders.

None of the officers of our general partner are employees of our general partner, and we do not have any employees.  Affiliates of our general partner and Vanguard conduct businesses and activities of their own in which we have no economic interest.  If these separate activities are significantly greater than our activities, there could be material competition for the time and effort of the officers and employees who provide services to our general partner, Vanguard, and their affiliates.  If the officers of our general partner and the employees of Vanguard and their affiliates do not devote sufficient attention to the management and operation of our business, our financial results may suffer and our ability to make distributions to our unitholders may be reduced.

Our partnership agreement limits our general partner’s fiduciary duties to unitholders and restricts the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

Our partnership agreement contains provisions that reduce the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty laws.  For example, our partnership agreement:

·  
permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner.  This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates, or any limited partner.  Examples include the exercise of its limited call right, the exercise of its rights to transfer or vote the units it owns, the exercise of its registration rights, and its determination whether or not to consent to any merger or consolidation of the partnership or amendment to the partnership agreement;
·  
provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as it acted in good faith;
·  
generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the conflicts committee of the board of directors of our general partner acting in good faith and not involving a vote of unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or must be “fair and reasonable” to us, as determined by our general partner in good faith.  In determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the totality of the relationships between the parties involved, including other transactions that may not be particularly advantageous or beneficial to us;
·  
provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for any acts or omissions unless there has been a final and nonappealable judgment entered by a court of competent jurisdiction determining that the general partner or its officers and directors acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and
·  
provides that in resolving conflicts of interest, it will be presumed that in making its decision the general partner or its conflicts committee acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.

Our unitholders are bound by the provisions in our partnership agreement, including the provisions discussed above.

Unitholders have limited voting rights and are not entitled to elect our general partner or its directors.

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business.  Unitholders do not elect our general partner or its board of directors on an annual or other continuing basis.  The board of directors of our general partner is chosen by Vanguard.  Furthermore, if the unitholders are dissatisfied with the performance of our general partner, they have little ability to remove our general partner.  As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.

Even if unitholders are dissatisfied, they cannot remove our general partner without its consent.

The unitholders are unable to remove our general partner without its consent because our general partner and its affiliates own sufficient units to be able to prevent its removal.  The vote of the holders of at least two-thirds of all outstanding units voting together as a single class is required to remove the general partner.  As of February 28, 2011, Vanguard owned approximately 46.1 percent of our outstanding common units.

 
29

 
Control of our general partner may be transferred to a third party without unitholder consent.

Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders.  Furthermore, our partnership agreement does not restrict the ability of Vanguard, the owner of our general partner, from transferring all or a portion of its ownership interest in our general partner to a third party.  The new owner of our general partner would then be in a position to replace the board of directors and officers of our general partner with its own choices and thereby influence the decisions made by the board of directors and officers.

We may issue additional units, including units that are senior to the common units, without unitholder approval.

Our partnership agreement does not limit the number of additional partner interests that we may issue.  In addition, we may issue an unlimited number of units that are senior to the common units in right of distribution, liquidation, and voting.  The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:

·  
our unitholders’ proportionate ownership interest in us will decrease;
·  
the amount of cash available for distribution on each unit may decrease;
·  
the ratio of taxable income to distributions may increase;
·  
the relative voting strength of each previously outstanding unit may be diminished; and
·  
the market price of our common units may decline.

Our partnership agreement restricts the voting rights of unitholders owning 20 percent or more of our common units, other than our general partner and its affiliates, which may limit the ability of significant unitholders to influence the manner or direction of management.

Our partnership agreement restricts unitholders’ voting rights by providing that any common units held by a person, entity, or group that owns 20 percent or more of any class of common units then outstanding, other than our general partner, its affiliates, their transferees, and persons who acquired such common units with the prior approval of the board of directors of our general partner, cannot vote on any matter.  Our partnership 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.

Affiliates of our general partner may sell common units in the public markets, which sales could have an adverse impact on the trading price of the common units.

As of February 28, 2011, Vanguard held 20,924,055 of our common units.  The sale of these units in the public markets could have an adverse impact on the price of the common units.

Our general partner has a limited call right that may require unitholders to sell their common units at an undesirable time or price.

As of February 28, 2011, Vanguard owned approximately 46.1 percent of our outstanding common units.  If at any time our general partner and its affiliates own more than 80 percent of the common units, our general partner will have 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 common units held by unaffiliated persons at a price not less than their then-current market price.  As a result, unitholders may be required to sell their common units at an undesirable time or price and may not receive any return on their investment.  Unitholders also may incur a tax liability upon a sale of their common units.

Unitholder liability may not be limited if a court finds that unitholder action constitutes control of our business.

A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner.  Our partnership is organized under Delaware law and we conduct business in a number of other states.  The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business.  A unitholder could be liable for our obligations as if it was a general partner if:
 
 
30

 
 
·  
a court or government agency determined that we were conducting business in a state but had not complied with that particular state’s partnership statute; or
·  
a unitholder’s  rights to act with other unitholders to remove or replace the general partner, to approve some amendments to our partnership agreement, or to take other actions under our partnership agreement constitute “control” of our business.

Unitholders may have liability to repay distributions.

Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them.  Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, or 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.  Liabilities to partners on account of their partnership interests and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.  Delaware law provides that for a period of three years from the date of an impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount.  A purchaser of common units who becomes a limited partner is liable for the obligations of the transferring limited partner to make contributions to the partnership that are known to such purchaser of common units at the time it became a limited partner and for unknown obligations if the liabilities could be determined from our partnership agreement.

Unitholders who are not Eligible Holders will not be entitled to receive distributions on or allocations of income or loss on their common units and their common units will be subject to redemption.

In order to comply with U.S. laws with respect to the ownership of interests in oil and natural gas leases on federal lands, we have adopted certain requirements regarding those investors who may own our common units.  As used herein, an Eligible Holder means a person or entity qualified to hold an interest in oil and natural gas leases on federal lands.  As of the date hereof, Eligible Holder means:

·  
a citizen of the United States;
·  
a corporation organized under the laws of the United States or of any state thereof;
·  
a public body, including a municipality; or
·  
an association of United States citizens, such as a partnership or limited liability company, organized under the laws of the United States or of any state thereof, but only if such association does not have any direct or indirect foreign ownership, other than foreign ownership of stock in a parent corporation organized under the laws of the United States or of any state thereof.

For the avoidance of doubt, onshore mineral leases or any direct or indirect interest therein may be acquired and held by aliens only through stock ownership, holding or control in a corporation organized under the laws of the United States or of any state thereof.  Unitholders who are not persons or entities who meet the requirements to be an Eligible Holder will not receive distributions or allocations of income and loss on their common units and they run the risk of having their common units redeemed by us at the lower of their purchase price cost or the then-current market price.  The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner.

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 or other securities may cause a corresponding decline in demand for riskier investments in general, including yield-based equity investments such as publicly traded limited partnership interests.  Reduced demand for our common units resulting from investors seeking other more favorable investment opportunities may cause the trading price of our common units to decline.

 
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Tax Risks to Common 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 additional entity-level taxation by individual states.  If the IRS were to treat us as a corporation or if we were to become subject to a material amount of additional entity-level taxation for state tax purposes, then our cash available for distribution to unitholders would be substantially reduced.

The anticipated after-tax economic benefit of an investment in the common units depends largely on our being treated as a partnership 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 income at the corporate tax rate, which is a maximum of 35 percent, and would likely pay state income tax at varying rates.  Distributions to unitholders generally would be taxed again as corporate distributions, and no income, gains, losses, or deductions would flow through to unitholders.  Because a tax would be imposed upon us as a corporation, our cash available for distribution to unitholders would be substantially reduced.  Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our common units.

Current law 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.  In addition, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise, and other forms of taxation.  For example, we are subject to an entity-level tax, the Texas margin tax, at an effective rate of up to 0.7 percent on the portion of our income that is apportioned to Texas.  Imposition of such a tax on us by Texas or any other state will reduce the cash available for distribution to unitholders.

The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial, or administrative changes and differing interpretations, possibly on a retroactive basis.

The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative, or judicial interpretation at any time.  For example, members of Congress are considering substantive changes to the existing federal income tax laws that affect certain publicly traded partnerships.  Any modification to the federal income tax laws and interpretations thereof may or may not be applied retroactively.  Although proposed legislation would not appear to affect our tax treatment as a partnership, we are unable to predict whether any of these changes, or other proposals, will ultimately be enacted.  Any such changes could negatively impact the value of an investment in our common units.

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.  Our counsel is unable to opine as to the validity of this method under applicable Treasury regulations.  If the IRS were to challenge this method or new Treasury regulations were issued, we may be required to change the allocation of items of income, gain, loss, and deduction among our unitholders.

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

We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us.  The IRS may adopt positions that differ from the conclusions of our counsel or from the positions we take.  It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel’s conclusions or the positions we take.  A court may not agree with some or all of our counsel’s conclusions or the positions we take.  Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade.  In addition, the costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner because the costs will reduce our cash available for distribution.

 
32

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

Because our unitholders are treated as partners to whom we allocate taxable income which could be different in amount than the cash we distribute, unitholders are required to pay any federal income taxes and, in some cases, state and local income taxes on their share of our taxable income, even if they receive no 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 the 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.  Prior distributions to unitholders in excess of the total net taxable income they were allocated for a common unit, which decreased their tax basis in that common unit, will, in effect, become taxable income to unitholders if the common unit is sold at a price greater than their tax basis in that common unit, even if the price they receive is less than their original cost.  A substantial portion of the amount realized, whether or not representing gain, may be ordinary income.  In addition, if unitholders sell their common units, they may incur a tax liability in excess of the amount of cash they receive from the sale.

Tax-exempt entities and foreign persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.

Investment in common units by tax-exempt entities, such as individual retirement accounts (known as IRAs) and other retirement plans, and foreign 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 them.  Distributions to foreign persons will be reduced by withholding taxes at the highest applicable effective tax rate, and foreign persons will be required to file United States federal income tax returns and pay tax on their share of our taxable income.

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, the unitholder 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, the unitholder 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.  Our tax counsel has not rendered an opinion regarding the treatment of a unitholder where common units are loaned to a short seller to cover a short sale of common units; therefore, 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.

We will treat each purchaser of common units as having the same tax benefits without regard to the common 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, we will adopt depletion, depreciation, and amortization positions that may not conform with all aspects of existing Treasury regulations.  Our counsel is unable to opine as to the validity of such filing positions.  A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to unitholders.  It also could affect the timing of these tax benefits or the amount of gain from unitholders’ sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to unitholder tax returns.

Unitholders likely will be subject to state and local taxes and return filing requirements as a result of investing in our common units.

In addition to federal income taxes, unitholders will likely be subject to other taxes, such as state and local income taxes, unincorporated business taxes, and estate, inheritance, or intangible taxes that are imposed by the various jurisdictions in which we do business or own property.  Unitholders likely will 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, unitholders may be subject to penalties for failure to comply with those requirements.  We own property and conduct business in Montana, North Dakota, Texas, New Mexico, Oklahoma, Arkansas, and Wyoming.  Of those states, Texas and Wyoming do not impose a state income tax on individuals.  We may own property or conduct business in other states or foreign countries in the future.  It is the unitholders’ responsibility to file all federal, state, and local tax returns.  Our counsel has not rendered an opinion on the state and local tax consequences of an investment in our common units.

 
33

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

We will be considered to have terminated for tax purposes if there is a sale or exchange of 50 percent or more of the total interests in our capital and profits within a twelve-month period.  Our termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns for one fiscal year and require a unitholder who uses a different taxable year than us to include more than twelve months of our taxable income or loss in his taxable income for the year of our termination.

The amount of taxable income or loss allocable to each unitholder depends in part upon values that we periodically determine for our outstanding equity interests and our assets in order to comply with federal income tax law.  The IRS may challenge our determinations of these values, which could adversely affect the value of our units.

Federal income tax law requires us to periodically determine the value of our assets and to calculate the amount of taxable income or loss allocable to each partner based in part upon these values.  We determine these asset values and allocations in part by reference to values that we determine for our outstanding equity interests.  The IRS may challenge our valuations and related allocations.  A successful IRS challenge to these valuations or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders.  It also could affect the amount of gain from our unitholders’ sale of units and could have a negative impact on the value of the units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.

Changes to current federal tax laws may affect unitholders’ ability to take certain tax deductions.

Substantive changes to the existing federal income tax laws have been proposed that, if adopted, would affect, among other things, the ability to take certain operations-related deductions, including deductions for intangible drilling and percentage depletion, and deductions for United States production activities.  We are unable to predict whether any changes, or other proposals to such laws, ultimately will be enacted.  Any such changes could negatively impact the value of an investment in our units.


We have no unresolved SEC staff comments received more than 180 days prior to December 31, 2010 that we believe are material.


We are a party to ongoing legal proceedings in the ordinary course of business.  Our general partner’s management does not believe the results of these legal proceedings will have a material adverse effect on our business, financial condition, results of operations, liquidity, or ability to pay distributions.

 
34

 



Our common units are listed on the NYSE under the symbol “ENP.”  The following table sets forth high and low sales prices of our common units and cash distributions to our common unitholders for the periods indicated:

         
Cash Distribution
   
         
Declared per
   
   
High
   
Low
   
Common Unit
 
Date Paid
 2010
                   
 Quarter ended December 31
  $ 22.59     $ 18.78     $ 0.5000  
2/14/2011
 Quarter ended September 30
  $ 21.33     $ 16.77     $ 0.5000  
11/12/2010
 Quarter ended June 30
  $ 21.63     $ 9.50     $ 0.5000  
8/13/2010
 Quarter ended March 31
  $ 21.80     $ 18.20     $ 0.5000  
5/14/2010
                           
 2009
                         
 Quarter ended December 31
  $ 20.97     $ 15.66     $ 0.5375  
2/12/2010
 Quarter ended September 30
  $ 17.27     $ 12.61     $ 0.5375  
11/13/2009
 Quarter ended June 30
  $ 18.62     $ 12.75     $ 0.5125  
8/14/2009
 Quarter ended March 31
  $ 16.91     $ 11.06     $ 0.5000  
5/15/2009

On February 18, 2011, the closing sales price of our common units as reported by the NYSE was $23.28 per unit and we had approximately 14 unitholders of record.  This number does not include owners for whom common units may be held in “street” name.

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

We did not purchase any of our common units during the fourth quarter of 2010.

Cash Distributions to Unitholders

Our partnership 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.  The term “available cash,” for any quarter, means all cash and cash equivalents on hand at the end of that quarter, less the amount of cash reserves established by our general partner to:

·  
provide for the proper conduct of our business;
·  
comply with applicable law, any of our debt instruments, or other agreements; or
·  
provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters.

Our partnership agreement gives our general partner wide latitude to establish reserves for future capital expenditures and operational needs prior to determining the amount of cash available for distribution.  We distribute available cash to our unitholders and our general partner in accordance with their ownership percentages.

As a general guideline, we plan to distribute to unitholders 50 percent of the excess distributable cash flow above: (1) maintenance capital requirements; (2) an implied minimum quarterly distribution of $0.4325 per unit, or $1.73 per unit annually; and (3) a minimum coverage ratio of 1.10.  The board of directors of our general partner may decide to make a fixed quarterly distribution over a specified period pursuant to the preceding formula in order to reduce some of the variability in quarterly distributions over the specified period.  Accordingly, we may make a distribution during a quarter even if we have not generated sufficient cash flow to cover such distribution by borrowing under our revolving credit facility, and we may reserve some of our cash during a quarter for distributions in future quarters even if the preceding formula would result in the distribution of a higher amount for such quarter.  Our partnership agreement permits our general partner to establish cash reserves to be used to pay distributions for any one or more of the next four quarters.  The board of directors of our general partner also may change our distribution philosophy based on prevailing business conditions.  There can be no assurance that we will be able to distribute $0.4325 on a quarterly basis or achieve a minimum coverage ratio of 1.10.
 
 
35

 
 

The following table shows selected historical financial data for the periods and as of the periods indicated.  The selected historical financial data as of December 31, 2010, 2009, and 2008 and for the years ended December 31, 2010, 2009, 2008, and 2007 is derived from our audited financial statements.  The selected historical financial data as of December 31, 2007 and 2006 and for the year ended December 31, 2006 is derived from unaudited financial statements.

The following selected consolidated financial and operating data should be read in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Item 8. Financial Statements and Supplementary Data”:
 
   
Year Ended December 31, (a)
 
   
2010
   
2009
   
2008
   
2007
   
2006
 
   
(in thousands, except per unit amounts)
 
 Consolidated Statements of Operations Data:
                             
    Revenues:
                             
       Oil
  $ 155,367     $ 128,404     $ 227,559     $ 136,082     $ 40,921  
       Natural gas
    28,109       21,635       53,864       38,792       40,440  
       Marketing (b)
    269       478       5,324       8,582       -  
    Total revenues
    183,745       150,517       286,747       183,456       81,361  
    Expenses:
                                       
       Production:
                                       
          Lease operating
    43,021       43,451       46,766       35,807       16,408  
          Production taxes and marketing (b)
    18,221       16,452       33,591       23,519       5,875  
       Depletion, depreciation, and amortization
    50,580       57,481       58,076       47,970       14,852  
       Exploration
    194       3,132       196       171       22  
       General and administrative (c)
    12,398       12,040       16,606       15,245       3,471  
       Derivative fair value loss (gain) (d)
    14,146       47,464       (96,880 )     26,301       -  
    Total expenses
    138,560       180,020       58,355       149,013       40,628  
    Operating income (loss)
    45,185       (29,503 )     228,392       34,443       40,733  
    Other income (expenses):
                                       
       Interest (e)
    (13,171 )     (10,974 )     (6,969 )     (12,702 )     -  
       Other
    56       162       95       43       -  
    Total other expenses
    (13,115 )     (10,812 )     (6,874 )     (12,659 )     -  
    Income (loss) before income taxes
    32,070       (40,315 )     221,518       21,784       40,733  
    Income tax benefit (provision)
    -       (14 )     (762 )     (78 )     (260 )
    Net income (loss)
  $ 32,070     $ (40,329 )   $ 220,756     $ 21,706     $ 40,473  
    Net income (loss) allocation (f):
                                       
       Limited partners' interest in net income (loss)
  $ 31,722     $ (39,913 )   $ 163,070     $ (18,877 )        
       General partner's interest in net income (loss)
  $ 348     $ (592 )   $ 2,648     $ (394 )        
    Net income (loss) per common unit (f):
                                       
       Basic
  $ 0.70     $ (1.01 )   $ 5.33     $ (0.79 )        
       Diluted
  $ 0.70     $ (1.01 )   $ 5.21     $ (0.79 )        
    Weighted average common units outstanding (f):
                                       
       Basic
    45,331       39,366       30,568       23,877          
       Diluted
    45,337       39,366       31,938       23,877          
    Cash distributions declared per common unit
  $ 2.04     $ 2.05     $ 2.31     $ 0.05          
 Total Production Volumes:
                                       
    Oil (Bbls)
    2,227       2,364       2,534       2,232       684  
    Natural gas (Mcf)
    5,836       6,097       6,219       5,751       5,990  
    Combined (BOE)
    3,200       3,380       3,571       3,190       1,683  
 Average Realized Prices:
                                       
    Oil ($/Bbl)
  $ 69.77     $ 54.33     $ 89.55     $ 60.97     $ 59.81  
    Natural gas ($/Mcf)
    4.82       3.55       8.76       6.75       6.75  
    Combined ($/BOE)
    57.34       44.39       78.81       54.81       48.36  
 Average Expenses per BOE:
                                       
    Lease operating
  $ 13.45     $ 12.86     $ 13.10     $ 11.22     $ 9.75  
    Production taxes and marketing (b)
    5.69       4.87       9.41       7.37       3.49  
    Depletion, depreciation, and amortization
    15.81       17.01       16.26       15.04       8.83  
    Exploration
    0.06       0.93       0.05       0.05       0.01  
    General and administrative (c)
    3.87       3.56       4.65       4.78       2.06  
    Derivative fair value loss (gain) (d)
    4.42       14.04       (27.13 )     8.24       -  
 Consolidated Statements of Cash Flows Data:
                                       
    Cash provided by (used in):
                                       
       Operating activities
  $ 121,351     $ 114,970     $ 189,235     $ 73,369     $ 62,031  
       Investing activities
    (7,119 )     (41,085 )     (42,333 )     (524,772 )     (8,836 )
       Financing activities
    (114,606 )     (72,750 )     (146,286 )     451,406       (53,195 )
 
 
 
36

 
 
   
As of December 31, (a)
 
   
2010
   
2009
   
2008
   
2007
   
2006
 
   
(in thousands)
 
 Proved Reserves:
                             
   Oil (Bbls)
    28,653       28,930       27,278       35,228       9,073  
   Natural gas (Mcf)
    74,527       84,699       78,011       83,238       76,824  
   Combined (BOE)
    41,074       43,047       40,280       49,101       21,877  
 Consolidated Balance Sheets Data:
                                       
   Working capital
  $ 2,663     $ 15,558     $ 71,563     $ 9,439     $ 3,128  
   Total assets
    653,562       719,651       813,313       749,144       211,287  
   Long-term debt
    234,000       255,000       150,000       47,500       -  
   Partners'/Owner's equity
    348,962       406,004       619,351       640,066       197,810  
_______
 
(a)
In March 2007, we acquired certain oil and natural gas properties and related assets in the Elk Basin of Wyoming and Montana.  The operating results of these properties are included with ours from the date of acquisition forward.
 
(b)
In conjunction with our Elk Basin acquisition in March 2007, we acquired a crude oil pipeline and a natural gas pipeline.  Prior to March 2007, we had no marketing activities and, therefore, no marketing revenues and expenses.
 
(c)
As a result of becoming a publicly traded entity in September 2007, we incur additional expenses such as fees associated with annual and quarterly reports to unitholders, tax returns, Schedule K-1 preparation and distribution, investor relations, registrar and transfer agent fees, incremental insurance costs, and accounting and legal services.  In addition, historically, Encore Operating received a fee based on our production for performing our administrative services and reimbursement of actual third-party expenses incurred on our behalf.  Pursuant to the Vanguard Acquisition, VNG will receive the administrative services fees and reimbursement of actual third-party expenses incurred on our behalf during 2011.
 
(d)
In conjunction with our Elk Basin acquisition in March 2007, EAC contributed floor contracts to us and we have subsequently purchased additional derivative contracts based on our risk management strategy.  Prior to March 2007, we had no derivative contracts and, therefore, no derivative fair value gains or losses.
        (e)
In conjunction with our Elk Basin acquisition in March 2007, we entered into two credit agreements.  Prior to March 2007, we had no indebtedness and, therefore, no interest expense.
 
(f)
Prior to the closing of our initial public offering in September 2007, EAC owned all of our general and limited partner interests, with the exception of management incentive units owned by then certain executive officers of our general partner.  Accordingly, earnings per unit is not presented for periods prior to our initial public offering.
 
 
37

 

The following discussion and analysis of our consolidated financial position and results of operations should be read in conjunction with our consolidated financial statements and notes, and supplementary data thereto included in “Item 8. Financial Statements and Supplementary Data.”  The following discussion and analysis contains forward-looking statements, including, without limitation, statements relating to our plans, strategies, objectives, expectations, intentions, and resources.  Actual results could differ materially from those discussed in these forward-looking statements.  We do not undertake to update, revise, or correct any of the forward-looking information unless required to do so under federal securities laws.  Readers are cautioned that such forward-looking statements should be read in conjunction with our disclosures under the headings: “Information Concerning Forward-Looking Statements” and “Item 1A.  Risk Factors.”

Introduction

In this management’s discussion and analysis of financial condition and results of operations, the following are discussed and analyzed:

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