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EX-32.1 - EX-32.1 - Encore Energy Partners LPd71103exv32w1.htm
EX-31.1 - EX-31.1 - Encore Energy Partners LPd71103exv31w1.htm
EX-32.2 - EX-32.2 - Encore Energy Partners LPd71103exv32w2.htm
EX-99.1 - EX-99.1 - Encore Energy Partners LPd71103exv99w1.htm
EX-31.2 - EX-31.2 - Encore Energy Partners LPd71103exv31w2.htm
EX-21.1 - EX-21.1 - Encore Energy Partners LPd71103exv21w1.htm
EX-23.1 - EX-23.1 - Encore Energy Partners LPd71103exv23w1.htm
EX-23.2 - EX-23.2 - Encore Energy Partners LPd71103exv23w2.htm
EX-12.1 - EX-12.1 - Encore Energy Partners LPd71103exv12w1.htm
Table of Contents

 
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, 2009
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
of incorporation or organization)
  (I.R.S. Employer
Identification No.)
     
777 Main Street, Suite 1400, Fort Worth, Texas
(Address of principal executive offices)
  76102
(Zip Code)
 
Registrant’s telephone number, including area code: (817) 877-9955
 
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, 2009 (the last business day of the registrant’s most
recently completed second fiscal quarter)   $ 317,874,042  
Number of Common Units outstanding as of February 17, 2010
    45,285,347  
 
DOCUMENTS INCORPORATED BY REFERENCE:
 
None
 


 

 
ENCORE ENERGY PARTNERS LP
 
INDEX
 
                 
        Page
 
PART I
  Items 1. and 2.     Business and Properties     1  
  Item 1A.     Risk Factors     24  
  Item 1B.     Unresolved Staff Comments     45  
  Item 3.     Legal Proceedings     45  
  Item 4.     Submission of Matters to a Vote of Security Holders     45  
 
PART II
  Item 5.     Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities     46  
  Item 6.     Selected Financial Data     47  
  Item 7.     Management’s Discussion and Analysis of Financial Condition and Results of Operations     50  
  Item 7A.     Quantitative and Qualitative Disclosures About Market Risk     75  
  Item 8.     Financial Statements and Supplementary Data     79  
  Item 9.     Changes in and Disagreements With Accountants on Accounting and Financial Disclosure     121  
  Item 9A.     Controls and Procedures     121  
  Item 9B.     Other Information     123  
 
PART III
  Item 10.     Directors, Executive Officers and Corporate Governance     123  
  Item 11.     Executive Compensation     129  
  Item 12.     Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters     134  
  Item 13.     Certain Relationships and Related Transactions, and Director Independence     137  
  Item 14.     Principal Accountant Fees and Services     139  
 
PART IV
  Item 15.     Exhibits and Financial Statement Schedules     140  
 EX-12.1
 EX-21.1
 EX-23.1
 EX-23.2
 EX-31.1
 EX-31.2
 EX-32.1
 EX-32.2
 EX-99.1


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ENCORE ENERGY PARTNERS LP
 
GLOSSARY
 
The following are abbreviations and definitions of certain terms used in this annual report on Form 10-K (the “Report”). The definitions of proved developed reserves, proved reserves, and proved undeveloped reserves have been abbreviated from the applicable definitions contained in Rule 4-10(a)(2-4) of Regulation S-X.
 
  •  ASC.  FASB Accounting Standards Codification.
 
  •  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.
 
  •  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.
 
  •  EAC.  Encore Acquisition Company, a publicly traded Delaware corporation, together with its subsidiaries.
 
  •  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.
 
  •  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.


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ENCORE ENERGY PARTNERS LP
 
 
  •  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 Margin.  Wellhead revenues less production expenses.
 
  •  Production Taxes.  Production expense attributable to production, ad valorem, and severance taxes.


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ENCORE ENERGY PARTNERS LP
 
 
  •  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.  Proved reserves that can be expected to be recovered from 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.
 
  •  Proved Reserves.  The estimated quantities of hydrocarbons, 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 under existing conditions and operating methods.
 
  •  Proved Undeveloped Reserves.  Proved reserves that are expected to be recovered from new wells on undrilled acreage for which the existence and recoverability of such reserves can be estimated with reasonable certainty, or from existing wells where a relatively major expenditure is required for recompletion. Includes unrealized production response from enhanced recovery techniques that have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.
 
  •  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.
 
  •  SFAS.  Statement of Financial Accounting Standards.
 
  •  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


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ENCORE ENERGY PARTNERS LP
 
  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.
 
  •  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.


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ENCORE ENERGY PARTNERS LP
 
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” refer to Encore Energy Partners Operating LLC, our operating company. References to “EAC” refer to Encore Acquisition Company, the ultimate parent company of our general partner, and its subsidiaries. References to “Encore Operating” refer to Encore Operating, L.P., a wholly owned subsidiary of EAC. 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.
 
PART I
 
ITEMS 1 and 2.   BUSINESS AND PROPERTIES
 
General
 
Our Business.  We are a Delaware limited partnership formed by EAC to acquire, exploit, and develop oil and natural gas properties and to acquire, own, and operate related assets. Our primary business objective is to make quarterly cash distributions to our unitholders at our current distribution rate and, over time, increase our quarterly cash distributions. 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.
 
EAC’s Merger with Denbury.  On October 31, 2009, EAC, the ultimate parent of our general partner, entered into an Agreement and Plan of Merger (the “Merger Agreement”) with Denbury Resources Inc. (“Denbury”) pursuant to which EAC has agreed to merge with and into Denbury, with Denbury as the surviving entity (the “Merger”). The Merger Agreement, which was unanimously approved by EAC’s Board of Directors and by Denbury’s Board of Directors, provides for Denbury’s acquisition of all of the issued and outstanding shares of EAC common stock. EAC expects to complete the Merger during the first quarter of 2010, although completion by any particular date cannot be assured.
 
Proved Reserves.  Our estimated total proved reserves at December 31, 2009 were 28.9 MMBbls of oil and 84.7 Bcf of natural gas, based on 2009 average market prices of $61.18 per Bbl of oil and $3.83 per Mcf of natural gas. On a BOE basis, our proved reserves were 43.0 MMBOE at December 31, 2009, of which 67 percent was oil, 92 percent was proved developed, and 8 percent was proved undeveloped.
 
Drilling.  In 2009, we participated in drilling 15 gross (1.8 net) non-operated productive wells. In 2009, we drilled one gross (1.0 net) dry hole. We invested $8.4 million in development, exploitation, and exploration activities in 2009.
 
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.
 
Our Relationship with Encore Acquisition Company
 
One of our principal attributes is our relationship with EAC. EAC is engaged in the acquisition and development of oil and natural gas reserves from onshore fields in the United States. Since 1998, EAC has


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ENCORE ENERGY PARTNERS LP
 
acquired producing properties with proven reserves and leasehold acreage and grown the production and proven reserves by drilling, exploring, reengineering or expanding existing waterflood projects, and applying tertiary recovery techniques. EAC’s fields are further characterized by large accumulations of original oil in place. Original oil in place is not an indication of how much oil is likely to be produced, but it is an indication of the estimated size of a reservoir. We believe that many of EAC’s oil and natural gas properties are, or after additional capital is invested may become, well suited for our partnership.
 
EAC constantly evaluates acquisitions and dispositions and may elect to acquire or dispose of oil and natural gas properties in the future without offering us the opportunity to purchase those assets. EAC has retained such flexibility because it believes it is in the best interests of its shareholders to do so. We cannot say with any certainty which, if any, opportunities to acquire assets from EAC may be made available to us or if we will choose to pursue any such opportunity. Moreover, EAC is not prohibited from competing with us and constantly evaluates acquisitions and dispositions that do not involve us.
 
In February 2008, we acquired certain oil and natural gas properties and related assets in the Permian Basin in West Texas and in the Williston Basin in North Dakota (the “Permian and Williston Basin Assets”) from Encore Operating for approximately $125.0 million in cash and the issuance of 6,884,776 ENP common units to Encore Operating. In determining the total purchase price, the common units were valued at $125.0 million. However, no accounting value was ascribed to the common units as the cash consideration exceeded Encore Operating’s carrying value of the properties. In January 2009, we acquired certain oil and natural gas properties and related assets in the Arkoma Basin in Arkansas and royalty interest properties primarily in Oklahoma, as well as 10,300 unleased mineral acres (the “Arkoma Basin Assets”), from Encore Operating for approximately $46.4 million in cash. In June 2009, we acquired certain oil and natural gas properties and related assets in the Williston Basin in North Dakota and Montana (the “Williston Basin Assets”) from Encore Operating for approximately $25.2 million in cash. In August 2009, we acquired certain oil and natural gas properties and related assets in the Big Horn Basin in Wyoming, the Permian Basin in West Texas and New Mexico, and the Williston Basin in Montana and North Dakota (the “Rockies and Permian Basin Assets”) from Encore Operating for approximately $179.6 million in cash. Because these assets were acquired from an affiliate, the acquisitions were accounted for as transactions between entities under common control, similar to a pooling of interests, whereby the assets and liabilities of the acquired properties were recorded at Encore Operating’s carrying value and our historical financial information was recast to include the acquired properties for all periods in which the properties were owned by Encore Operating. Accordingly, the information contained in this Report reflects our historical results combined with those of the Permian and Williston Basin Assets, the Arkoma Basin Assets, the Williston Basin Assets, and the Rockies and Permian Basin Assets.


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ENCORE ENERGY PARTNERS LP
 
Organizational Structure
 
The following diagram depicts our organizational structure as of February 17, 2010:
 
(ORGANIZATIONAL STRUCTURE LOGO)
 
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, 2009, we operated properties representing approximately 85 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 2009, 2008, and 2007, our development costs on non-operated properties were approximately 66 percent, 24 percent, and 28 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.
 
We do not have any employees. Encore Operating provides administrative services for us, such as accounting, corporate development, finance, land, legal, and engineering pursuant to an administrative services agreement. In addition, Encore Operating provides all personnel, facilities, goods, and equipment necessary to perform these services which are not otherwise provided by us. Encore Operating is not liable to us for its


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ENCORE ENERGY PARTNERS LP
 
performance of, or failure to perform, services under the administrative services agreement unless its acts or omissions constitute gross negligence or willful misconduct.
 
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. Effective April 1, 2009, the administrative fee increased to $2.02 per BOE of our production. ENP also reimburses Encore Operating for actual third-party expenses incurred on our behalf. Encore Operating has substantial discretion in determining which third-party expenses to incur on our behalf. In addition, Encore Operating 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.
 
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, Encore Operating 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 Encore Operating 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 are operated for us by Encore Operating 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.


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ENCORE ENERGY PARTNERS LP
 
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,  
    2009     2008     2007  
 
Total Production Volumes:
                       
Oil (MBbls)
    2,337       2,533       2,232  
Natural gas (MMcf)
    6,097       6,219       5,751  
Combined (MBOE)
    3,353       3,570       3,190  
Average Daily Production Volumes:
                       
Oil (Bbl/D)
    6,402       6,922       6,114  
Natural gas (Mcf/D)
    16,703       16,991       15,756  
Combined (BOE/D)
    9,186       9,754       8,740  
Average Realized Prices:
                       
Oil (per Bbl)
  $ 54.61     $ 89.45     $ 60.74  
Natural gas (per Mcf)
    3.68       8.67       6.80  
Combined (per BOE)
    44.75       78.59       54.75  
Average Costs per BOE:
                       
Lease operating
  $ 12.43     $ 12.54     $ 10.65  
Production, ad valorem, and severance taxes
    4.80       7.88       5.55  
Depletion, depreciation, and amortization
    16.93       16.12       14.89  
Exploration
    0.93       0.05       0.04  
Derivative fair value loss (gain)
    14.16       (27.14 )     8.24  
General and administrative
    3.39       4.65       4.78  
Other operating
    0.92       0.47       0.45  
Marketing, net of revenues
    (0.05 )     0.04       (0.60 )
 
Productive Wells
 
The following table sets forth information relating to the productive wells in which we owned a working interest as of December 31, 2009. 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
    352       271.5       77 %     41       29.6       72 %
Williston Basin
    100       63.9       64 %     23       6.3       27 %
Permian Basin
    1,538       373.8       24 %     561       273.7       49 %
Arkoma Basin
    5       0.3       6 %     123       9.1       7 %
                                                 
Total
    1,995       709.5       36 %     748       318.7       43 %
                                                 
 
 
(a) Our total wells include 1,099 operated wells and 1,644 non-operated wells. At December 31, 2009, 35 of our wells had multiple completions.


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ENCORE ENERGY PARTNERS LP
 
 
Acreage
 
The following table sets forth information relating to our leasehold acreage at December 31, 2009. 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, 2009, our undeveloped acreage in the Permian Bain represented approximately 58 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.
 
                 
    Gross Acreage     Net Acreage  
 
Big Horn Basin:
               
Developed
    16,267       13,360  
Undeveloped
           
                 
      16,267       13,360  
                 
Williston Basin:
               
Developed
    46,738       37,535  
Undeveloped
    10,546       7,361  
                 
      57,284       44,896  
                 
Permian Basin:
               
Developed
    59,826       34,559  
Undeveloped
    8,244       10,279  
                 
      68,070       44,838  
                 
Arkoma Basin:
               
Developed
    3,192       357  
Undeveloped
    357       84  
                 
      3,549       441  
                 
Total:
               
Developed
    126,023       85,811  
Undeveloped
    19,147       17,724  
                 
      145,170       103,535  
                 
 
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.


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ENCORE ENERGY PARTNERS LP
 
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,  
    2009     2008     2007  
   
Gross
   
Net
   
Gross
   
Net
   
Gross
   
Net
 
 
Development Wells:
                                               
Productive
    9       1.2       49       15.3       43       13.5  
Dry holes
                                   
                                                 
      9       1.2       49       15.3       43       13.5  
                                                 
Exploratory Wells:
                                               
Productive
    6       0.6       10       1.3       7       3.7  
Dry holes
    1       1.0       1       0.0       2       1.0  
                                                 
      7       1.6       11       1.3       9       4.7  
                                                 
Total:
                                               
Productive
    15       1.8       59       16.6       50       17.2  
Dry holes
    1       1.0       1       0.0       2       1.0  
                                                 
      16       2.8       60       16.6       52       18.2  
                                                 
 
Present Activities
 
As of December 31, 2009, we had two gross (0.1 net) development wells that had reached total depth and were in the process of being completed pending first production.
 
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.
 
Our natural gas production and gathered natural gas from operated Permian Basin properties is generally sold 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 from operated Permian Basin 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


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ENCORE ENERGY PARTNERS LP
 
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. Increases 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 2009:
 
                                 
    First Quarter
    Second Quarter
    Third Quarter
    Fourth Quarter
 
    of 2009     of 2009     of 2009     of 2009  
 
Average oil wellhead to NYMEX percentage
    86 %     91 %     89 %     89 %
Average natural gas wellhead to NYMEX percentage
    69 %     92 %     100 %     107 %
 
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 liquids 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 resulting in a price we were paid per Mcf under certain contracts to be higher than the average NYMEX price.
 
Principal Customers
 
For 2009, our largest purchaser was Marathon Oil Corporation, which accounted for 43 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. Management believes that the loss of any one purchaser would not have a material adverse effect on our ability to market our oil and natural gas production.
 
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.
 
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.


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ENCORE ENERGY PARTNERS LP
 
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)  
 
2009
                                                       
Big Horn Basin
    1,422       337       1,478       44 %   $ 54.33     $ 0.94     $ 12.82  
Williston Basin
    412       291       461       14 %     53.35       3.87       17.40  
Arkoma Basin
    21       963       182       5 %     53.33       2.83       1.10  
Permian Basin
    482       4,506       1,232       37 %     56.57       4.05       11.78  
                                                         
Total
    2,337       6,097       3,353       100 %     54.61       3.68       12.43  
                                                         
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
    541       4,523       1,295       36 %     96.73       9.29       12.10  
                                                         
Total
    2,533       6,219       3,570       100 %     89.45       8.67       12.54  
                                                         
2007
                                                       
Big Horn Basin
    1,287       286       1,334       42 %     55.15       1.90       11.48  
Williston Basin
    380       305       431       14 %     68.37       6.19       11.18  
Arkoma Basin
    18       1,048       192       6 %     67.98       6.08       0.75  
Permian Basin
    547       4,112       1,233       39 %     68.29       7.37       11.11  
                                                         
Total
    2,232       5,751       3,190       100 %     60.74       6.80       10.65  
                                                         


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ENCORE ENERGY PARTNERS LP
 
The following table sets forth the proved reserves of our properties by principal area of operation as of December 31, 2009:
 
                                 
          Natural
          Percent
 
    Oil     Gas     Total     of Total  
    (MBbls)     (MMcf)     (MBOE)        
 
Proved Developed:
                               
Big Horn Basin
    15,638       1,374       15,867       40 %
Williston Basin
    4,513       3,361       5,073       13 %
Arkoma Basin
    204       7,813       1,506       4 %
Permian Basin
    5,986       65,831       16,958       43 %
                                 
Total Proved Developed
    26,341       78,379       39,404       100 %
                                 
Proved Undeveloped:
                               
Big Horn Basin
    1,044             1,044       29 %
Williston Basin
    522       243       563       15 %
Permian Basin
    1,023       6,077       2,036       56 %
                                 
Total Proved Undeveloped
    2,589       6,320       3,643       100 %
                                 
Total Proved:
                               
Big Horn Basin
    16,682       1,374       16,911       39 %
Williston Basin
    5,035       3,604       5,636       13 %
Arkoma Basin
    204       7,813       1,506       4 %
Permian Basin
    7,009       71,908       18,994       44 %
                                 
Total Proved
    28,930       84,699       43,047       100 %
                                 
 
At December 31, 2009, the total quantity of proved undeveloped reserves was 3.6 MMBOE, which was 22 percent higher than the balance at December 31, 2008. This increase is primarily attributable to an increase in the amount of reserves that are allowed to be classified as proved undeveloped, in accordance with the SEC’s new rules on oil and natural gas reserves, partially offset by a decrease due to the conversion of properties from proved undeveloped to proved developed reserves.
 
The following table sets forth the PV-10 of our properties by principal area of operation as of December 31, 2009:
 
                 
    Amount(a)     Percent of Total  
    (In thousands)        
 
Big Horn Basin
  $ 263,965       53 %
Williston Basin
    73,445       15 %
Arkoma Basin
    15,765       3 %
Permian Basin
    146,598       29 %
                 
Total
  $ 499,773       100 %
                 
 
 
(a) Giving effect to commodity derivative contracts, our PV-10 would increase by $0.2 million at December 31, 2009. Standardized Measure at December 31, 2009 was $494.5 million. Standardized Measure differs from PV-10 by approximately $5.3 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.


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ENCORE ENERGY PARTNERS LP
 
 
Proved Reserves
 
Recent 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. Application of the new reserve rules resulted in the use of lower prices at December 31, 2009 for both oil and natural gas than would have resulted under the previous rules. Use of new 12-month average pricing rules at December 31, 2009 resulted in a decrease in proved reserves of approximately 2.2 MMBOE. Pursuant to the SEC’s final rule, prior period reserves were not restated.
 
The SEC’s new rules expanded the technologies that a company can use to establish reserves. The SEC now 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 2009 reserves estimates.
 
Proved Undeveloped Reserves (“PUDs”).  As of December 31, 2009, our PUDs totaled 2.6 MMBbls of crude oil and 6.3 Bcf of natural gas, for a total of 3.6 MMBOE or about 8.5 percent of our total proved reserves.
 
All of our PUDs as of December 31, 2009 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 and guidance and prepared in accordance with generally accepted petroleum engineering principles. We engage a third-party petroleum consulting firm, Miller and Lents, Ltd. (“Miller and Lents”) to prepare our reserves. Responsibility for compliance in reserves bookings is delegated to the Reserves and Planning Engineering Manager and requires that reserves estimates be made by the regional reservoir engineering staff for our different geographical regions. These reserves estimates are reviewed and approved by regional management and senior engineering staff with final approval by the Reserves and Planning Engineering Manager and the Senior Vice President and Chief Operating Officer and certain members of senior management.
 
Our Reserves and Planning Engineering Manager is the technical person primarily responsible for overseeing the preparation of our reserves estimates. She has a Bachelor of Science degree in Petroleum Engineering, 15 years of industry experience, and 9 years experience managing our reserves with positions of increasing responsibility in engineering and evaluations. The Reserves and Planning Engineering Manager reports directly to our Senior Vice President and Chief Operating Officer.
 
The engineers and geologists of Miller and Lents have an average of 30 years of relevant industry experience in the estimation, assessment, and evaluation of oil and natural gas reserves. They have significant industry experience in virtually all petroleum-producing basins in the world and meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Miller and Lents is an independent firm of petroleum engineers, geologists, geophysicists, and petrophysicists; it does not own an interest in our properties and is not employed on a contingent fee basis. Miller and Lents’ report on our reserves and future net revenues as of December 31, 2009, which details specific information regarding the scope of work undertaken and the results thereof, is filed as Exhibit 99.1 to this Report and incorporated herein by reference.


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ENCORE ENERGY PARTNERS LP
 
Guidelines 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.
 
Other Reserve Information.  During 2009, we filed the estimates of our oil and natural gas reserves as of December 31, 2008 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.
 
(NATURAL GAS RESERVE LOGO)
 
Big Horn Basin Properties
 
Our Big Horn Basin properties, which include our Elk Basin Assets 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 2009, production from our Big Horn Basin properties averaged approximately 4,049 BOE/D, of which approximately 96 percent was oil. Our Big Horn Basin properties had estimated proved reserves at December 31, 2009 of 16.9 MMBOE, of which 15.9 MMBOE was proved developed and 1.0 MMBOE was proved undeveloped.


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ENCORE ENERGY PARTNERS LP
 
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, 2009 of 12.5 MMBOE, of which 11.5 MMBOE was proved developed and 1.0 MMBOE was proved undeveloped.
 
Our properties in the Elk Basin area include 16,267 gross acres (13,360 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, 2009, the Embar-Tensleep formation had estimated total proved reserves of 4.7 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, 2009 of 6.3 MMBOE, all of which were oil and 87 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 95 percent working interest and an average 81 percent net revenue interest in our wells in the Frontier formation. The Frontier formation had estimated total proved reserves at December 31, 2009 of 543 MBOE, 67 percent of which were oil and all of which were proved developed.
 
Other Oil and Natural Gas Properties.  We also operate wells in the Big Horn, Embar-Tensleep, and Madison formations in the Northwest Elk Basin field and in the Embar-Tensleep, Middle Frontier, Torchlight, and Peay Sand formations in the South Elk Basin field. We hold an average 83 percent working interest and an average 71 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, 2009 of 725 MBOE, 93 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.


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ENCORE ENERGY PARTNERS LP
 
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 2009, the Elk Basin natural gas processing plant produced approximately 421 net Bbls of NGLs per day, primarily 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 4,000 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.
 
The Wildhorse pipeline system is an approximately 12-mile natural gas gathering system that transports approximately 1.0 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 13.5 MMcf/D of high sulfur natural gas from the Elk Basin field to our Elk Basin natural gas processing plant.
 
Gooseberry Field
 
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 23 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, 2009 of 4.4 MMBOE, all of which were oil and all of which were proved developed.
 
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. The Horse Creek field is located in Bowman County, North Dakota and has producing oil wells from multiple horizons in the Red River formation. The Charlson Madison Unit produces from the unitized Madison formation. The Elk field is operated and produces from wells in McKenzie County, North Dakota.
 
During 2009, production from our Williston Basin properties averaged approximately 1,262 BOE/D, of which approximately 89 percent was oil. Our Williston Basin properties had estimated proved reserves at December 31, 2009 of 5.6 MMBOE, of which 5.1 MMBOE were proved developed. During 2009, we drilled 1 gross (0.3 net) wells.
 
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 2009, production from our Permian Basin properties was approximately 20,262 MMcfe/D, 61 percent of which was natural gas. Our Permian Basin properties had estimated proved reserves at December 31, 2009


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of 114.0 Bcfe, of which 101.8 Bcfe was proved developed and 12.2 Bcfe was proved undeveloped. As of December 31, 2009, our Permian Basin properties consisted of 68,070 gross (44,838 net) acres.
 
Operated Properties.  In West Texas, we operate 763 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.
 
The five 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, 2009, 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 quality drilling locations remaining to be developed. We have identified 5.9 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. Historically, we have participated with this company in drilling 2 to 4 wells per year.
 
Arkoma 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 Arkoma Basin properties consist of non-operated working interests in over 100 producing wells in the Chismville field. At December 31, 2009, the properties had total proved reserves of approximately 1.5 MMBOE, all of which is proved developed producing and 86 percent of which


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are natural gas. During 2009, the production from our Arkoma properties averaged approximately 2,988 MMcfe/D, of which 88 percent is natural gas. During 2009, we drilled 14 gross (1.5 net) wells.
 
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.
 
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.


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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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The 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, 2009, we have recorded $4.7 million as future abandonment liability 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


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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.
 
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


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capital expenditures for remediation or pollution control activities during 2009, 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.
 
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


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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.
 
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


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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, Minerals Management Service, and other agencies.
 
Operating Hazards and Insurance
 
The oil and natural gas business involves a variety of operating risks, including fires, explosions, blowouts, environmental hazards, and other potential events that can adversely affect our ability to conduct operations and cause us to incur substantial losses. Such losses could reduce or eliminate the funds available for exploration, exploitation, or leasehold acquisitions or result in loss of properties.
 
In accordance with industry practice, we maintain insurance against some, but not all, potential risks and losses. We do not carry business interruption insurance. We may not obtain insurance for certain risks if we believe the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable at a reasonable cost. If a significant accident or other event occurs that is not fully covered by insurance, it could adversely affect us.
 
Employees
 
The officers of our general partner manage our operations and activities. However, neither we nor our general partner have employees. Encore Operating performs 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.”
 
As of December 31, 2009, EAC had a staff of 421 persons, including 35 engineers, 18 geologists, and 13 landmen, none of which are represented by labor unions or covered by any collective bargaining agreement. We believe that EAC’s relations with its employees are satisfactory.
 
Principal Executive Office
 
Our principal executive office is located at 777 Main Street, Suite 1400, Fort Worth, Texas 76102. Our main telephone number is (817) 877-9955.
 
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, N.E., Room 1580, Washington, D.C. 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


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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.


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ITEM 1A.   RISK FACTORS
 
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
 
If the Merger between EAC and Denbury is not completed, it could negatively affect the price of our common units and future business and operations.
 
There is no assurance that the Merger between EAC and Denbury will be completed. If the Merger is not completed for any reason, we and EAC may be subject to a number of risks, including the following:
 
  •  EAC may not realize the benefits expected from the Merger, including a potentially enhanced financial and competitive position, which in turn could negatively affect our financial and competitive position; and
 
  •  the current market price of our common units may reflect a market assumption that the Merger will occur and a failure to complete the Merger could result in a decline in the market price of our common units.
 
Delays in competing the Merger could exacerbate uncertainties concerning the effect of the Merger, which may have an adverse effect on our business following the Merger and could defer or detract from the realization of the benefits expected to result from the Merger.
 
There may be substantial disruption to our business and distraction of our management and employees as a result of the Merger.
 
All of the executive officers of our general partner are also executive officers of EAC, and all of our employees are provided by Encore Operating, a subsidiary of EAC. There may be substantial disruption to our business and distraction of our management and employees from day-to-day operations because matters related to the Merger may require substantial commitments of time and resources, which could otherwise have been devoted to other opportunities that could have been beneficial to us.
 
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 Encore Operating.
 
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;


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  •  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.
 
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 growth 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.


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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.
 
The worldwide financial and credit crisis has 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 in 2008 and 2009, which is expected to continue into 2010. The slowdown in economic activity has 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;


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  •  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.
 
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


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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 2012. These contracts are intended to reduce our exposure to fluctuations in the price of oil and natural gas. After 2012, 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, 2009, we were entitled to future payments of approximately $26.3 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 reserve 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


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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.
 
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.


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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.
 
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.


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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 2009, our largest purchaser was Marathon Oil Corporation, which accounted for 43 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.
 
As of February 17, 2010, we had $260 million of outstanding borrowings and $115 million of borrowing capacity under our revolving credit facility. We have the ability to incur additional debt under our revolving


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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.
 
We are unable to predict the impact of the recent downturn in the credit markets and the resulting costs or constraints in obtaining financing on our business and financial results.
 
U.S. and global credit and equity markets have recently undergone significant disruption, making it difficult for many businesses to obtain financing on acceptable terms. In addition, equity markets are continuing to experience wide fluctuations in value. If these conditions continue or worsen, our cost of borrowing may increase, and it may be more difficult to obtain financing in the future. In addition, an increasing number of financial institutions have reported significant deterioration in their financial condition. If any of the financial institutions are unable to perform their obligations under our revolving credit agreements and other contracts, and we are unable to find suitable replacements on acceptable terms, our results of operations, liquidity and cash flows could be adversely affected. We also face challenges relating to the impact of the disruption in the global financial markets on other parties with which we do business, such as customers and suppliers. The inability of these parties to obtain financing on acceptable terms could impair their ability to perform under their agreements with us and lead to various negative effects on us, including business disruption, decreased revenues, and increases in bad debt write-offs. A sustained decline in the financial stability of these parties could have an adverse impact on our business, results of operations, liquidity, and ability to make distributions.
 
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


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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.
 
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. Changes in the insurance markets due to weather and adverse economic conditions have made it more difficult for us to obtain certain types of coverage. We may not be able to obtain the levels or types of insurance we would otherwise have obtained prior to these market changes, and our insurance may contain large deductibles or fail to cover certain hazards or cover all potential losses. Losses and liabilities from uninsured and underinsured events and


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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 15 percent of our properties (measured by total reserves) and approximately 60 percent of our wells as of December 31, 2009. 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.
 
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


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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, exploitation, and exploration 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, exploitation, and exploration 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.


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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 17, 2010, EAC owned approximately 45.7 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 EAC. Furthermore, certain directors and officers of our general partner are directors and officers of affiliates of our general partner, including EAC. Conflicts of interest may arise between EAC 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 EAC or its affiliates (other than our general partner) to pursue a business strategy that favors us. EAC’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 EAC and its affiliates, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to our unitholders;
 
  •  EAC 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 EAC) 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;
 
  •  Encore Operating performs administrative services for us pursuant to an administrative services agreement under which it receives an administrative fee of $2.02 per BOE of our production for such services and reimbursement of actual third-party expenses incurred on our behalf. Encore Operating has substantial discretion in determining which third-party expenses to incur on our behalf. In addition, Encore Operating 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;


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  •  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.
 
EAC is not limited in its ability to compete with us, which could limit our ability to acquire additional assets or businesses.
 
Our partnership agreement does not prohibit EAC from owning assets or engaging in businesses that compete directly or indirectly with us. In addition, EAC may acquire, develop, or dispose of additional oil and natural gas properties or other assets, without any obligation to offer us the opportunity to purchase or develop any of those assets. EAC is an established participant in the oil and natural gas industry and has significantly greater resources and experience than we have, which factors may make it more difficult for us to compete with EAC with respect to commercial activities as well as for acquisition candidates. As a result, competition from EAC could adversely impact our results of operations and cash available for distribution.
 
EAC, as the owner of our general partner, has the power to appoint and remove our directors and management.
 
Since an affiliate of EAC 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 EAC also owned approximately 45.7 percent of our outstanding common units as of February 17, 2010, 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 EAC and our general partner relating to us may not be consistent with those of a majority of the public unitholders.
 
We do not have any employees and rely solely on officers of our general partner and employees of EAC. 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 Encore Operating conduct businesses and activities of their own in which we have no economic interest, including businesses and activities relating to EAC. 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, EAC, and their affiliates. If the officers of our general partner and the employees of EAC 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.


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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 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 EAC. 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


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two-thirds of all outstanding units voting together as a single class is required to remove the general partner. As of February 17, 2010, EAC owned approximately 45.7 percent of our outstanding common units.
 
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 EAC, 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 17, 2010, EAC 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 17, 2010, EAC owned approximately 45.7 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


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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:
 
  •  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


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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.
 
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


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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.
 
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


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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.
 
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.


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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.
 
ITEM 1B.   UNRESOLVED STAFF COMMENTS
 
There were no unresolved SEC staff comments as of December 31, 2009.
 
ITEM 3.   LEGAL PROCEEDINGS
 
We are a party to ongoing legal proceedings in the ordinary course of business. Our general partner’s management does not believe the result of these legal proceedings will have a material adverse effect on our business, financial condition, results of operations, liquidity, or ability to pay distributions.
 
ITEM 4.   SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
 
There were no matters submitted to a vote of unitholders during the fourth quarter of 2009.


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PART II
 
ITEM 5.   MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
 
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
   
2009
  High   Low   Common Unit   Date Paid
 
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  
                                 
2008
                               
Quarter ended December 31
  $ 22.10     $ 8.34     $ 0.5000       2/13/2009  
Quarter ended September 30
  $ 28.73     $ 18.08     $ 0.6600       11/14/2008  
Quarter ended June 30
  $ 28.50     $ 18.80     $ 0.6881       8/14/2008  
Quarter ended March 31
  $ 21.50     $ 17.92     $ 0.5755       5/15/2008  
 
On February 17, 2010, the closing sales price of our common units as reported by the NYSE was $20.20 per unit and we had approximately 11 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 2009.
 
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


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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. 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.
 
ITEM 6.   SELECTED FINANCIAL DATA
 
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, 2009 and 2008 and for the years ended December 31, 2009, 2008, and 2007 is derived from our audited financial statements. The selected historical financial data as of December 31, 2007, 2006, and 2005 and for the years ended December 31, 2006 and 2005 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)  
    2009     2008     2007     2006     2005  
    (In thousands, except per unit amounts)  
 
Consolidated Statements of Operations Data:
                                       
Revenues:
                                       
Oil
  $ 127,611     $ 226,613     $ 135,546     $ 40,900     $ 22,832  
Natural gas
    22,428       53,944       39,119       40,461       52,631  
Marketing(b)
    478       5,324       8,582              
                                         
Total revenues
    150,517       285,881       183,247       81,361       75,463  
                                         
Expenses:
                                       
Production:
                                       
Lease operating
    41,676       44,752       33,980       14,094       8,594  
Production, ad valorem, and severance taxes
    16,099       28,147       17,712       7,026       5,584  
Depletion, depreciation, and amortization
    56,757       57,537       47,494       14,697       11,880  
Exploration
    3,132       196       126       22       312  
General and administrative(c)
    11,375       16,605       15,245       3,471       2,567  
Marketing(b)
    302       5,466       6,673              
Derivative fair value loss (gain)(d)
    47,464       (96,880 )     26,301              
Other operating
    3,099       1,670       1,426       1,318       1,374  
                                         
Total expenses
    179,904       57,493       148,957       40,628       30,311  
                                         
Operating income (loss)
    (29,387 )     228,388       34,290       40,733       45,152  
                                         
Other income (expenses):
                                       
Interest(e)
    (10,974 )     (6,969 )     (12,702 )            
Other
    46       99       196              
                                         
Total other expenses
    (10,928 )     (6,870 )     (12,506 )            
                                         
Income (loss) before income taxes
    (40,315 )     221,518       21,784       40,733       45,152  
Income tax provision
    (14 )     (762 )     (78 )     (260 )     (27 )
                                         
Net income (loss)
  $ (40,329 )   $ 220,756     $ 21,706     $ 40,473     $ 45,125  
                                         
Net income (loss) allocation(f):
                                       
Limited partners’ interest in net income (loss)
  $ (39,913 )   $ 163,070     $ (18,877 )                
                                         
General partner’s interest in net income (loss)
  $ (592 )   $ 2,648     $ (394 )                
                                         
Net income (loss) per common unit(f):
                                       
Basic
  $ (1.01 )   $ 5.33     $ (0.79 )                
Diluted
  $ (1.01 )   $ 5.21     $ (0.79 )                
Weighted average common units outstanding(f):
                                       
Basic
    39,366       30,568       23,877                  
Diluted
    39,366       31,938       23,877                  
Cash distributions declared per common unit
  $ 2.0500     $ 2.3111     $ 0.0530                  


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    Year Ended December 31,(a)  
    2009     2008     2007     2006     2005  
    (In thousands, except per unit amounts)  
 
Total Production Volumes:
                                       
Oil (Bbls)
    2,337       2,533       2,232       684       437  
Natural gas (Mcf)
    6,097       6,219       5,751       5,990       6,639  
Combined (BOE)
    3,353       3,570       3,190       1,683       1,544  
Average Realized Prices:
                                       
Oil ($/Bbl)
  $ 54.61     $ 89.45     $ 60.74     $ 59.78     $ 52.20  
Natural gas ($/Mcf)
    3.68       8.67       6.80       6.76       7.93  
Combined ($/BOE)
    44.75       78.59       57.44       48.36       48.88  
Average Expenses per BOE:
                                       
Lease operating
  $ 12.43     $ 12.54     $ 10.65     $ 8.38     $ 5.57  
Production, ad valorem, and severance taxes
    4.80       7.88       5.55       4.18       3.62  
Depletion, depreciation, and amortization
    16.93       16.12       14.89       8.74       7.70  
Exploration
    0.93       0.05       0.04       0.01       0.20  
General and administrative(c)
    3.39       4.65       4.78       2.06       1.66  
Derivative fair value loss (gain)(d)
    14.16       (27.14 )     8.24              
Other operating
    0.92       0.47       0.45       0.78       0.89  
Marketing, net of revenues(b)
    (0.05 )     0.04                    
Consolidated Statements of Cash Flows Data:
                                       
Cash provided by (used in):
                                       
Operating activities
  $ 114,970     $ 189,235     $ 73,369     $ 62,031     $ 50,530  
Investing activities
    (41,085 )     (42,333 )     (524,772 )     (8,836 )     (104,480 )
Financing activities
    (72,750 )     (146,286 )     451,406       (53,195 )     53,950  
 
                                         
    As of December 31,(a)  
    2009     2008     2007     2006     2005  
    (In thousands)  
 
Proved Reserves:
                                       
Oil (Bbls)
    28,930       27,278       35,228       9,073       8,992  
Natural gas (Mcf)
    84,699       78,011       83,238       76,824       85,712  
Combined (BOE)
    43,047       40,280       49,101       21,877       23,277  
Consolidated Balance Sheets Data:
                                       
Working capital
  $ 15,558     $ 71,563     $ 9,439     $ 3,128     $ 10,174  
Total assets
    719,651       813,313       749,144       211,287       222,432  
Long-term debt
    255,000       150,000       47,500              
Partners’/Owner’s equity
    406,004       619,351       640,066       197,810       210,352  
 
 
(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, Encore Operating receives a fee based on our production for performing our administrative services, and receives reimbursement of actual third-party expenses incurred on our behalf.
 
(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.

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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 certain executive officers of our general partner. Accordingly, earnings per unit is not presented for periods prior to our initial public offering.


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ITEM 7.   MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
 
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:
 
  •  Overview of Business
 
  •  2009 Highlights
 
  •  Results of Operations
 
  —  Comparison of 2009 to 2008
 
  —  Comparison of 2008 to 2007
 
  •  Capital Commitments, Capital Resources, and Liquidity
 
  •  Changes in Prices
 
  •  Critical Accounting Policies and Estimates
 
  •  New Accounting Pronouncements
 
  •  Information Concerning Forward-Looking Statements
 
Overview of Business
 
We are a Delaware limited partnership formed by EAC to acquire, exploit, and develop oil and natural gas properties and to acquire, own, and operate related assets. Our primary business objective is to make quarterly cash distributions to our unitholders at our current distribution rate and, over time, increase our quarterly cash distributions.
 
As previously discussed, on October 31, 2009, EAC, the ultimate parent of our general partner, entered into the Merger Agreement with Denbury, pursuant to which EAC will merge with and into Denbury, with Denbury as the surviving entity. The Merger Agreement, which was unanimously approved by EAC’s Board of Directors and by Denbury’s Board of Directors, provides for Denbury’s acquisition of all of the issued and outstanding shares of EAC common stock. EAC and Denbury expect to complete the Merger during the first quarter of 2010, although completion by any particular date cannot be assured.
 
In September 2007, we completed our initial public offering (the “IPO”) of 9,000,000 common units at a price to the public of $21.00 per unit. In October 2007, the underwriters exercised their option to purchase an additional 1,148,400 common units. The net proceeds of approximately $193.5 million, after deducting the underwriters’ discount and a structuring fee of approximately $14.9 million, in the aggregate, and offering expenses of approximately $4.7 million, were used to repay in full $126.4 million of outstanding indebtedness


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under a subordinated credit agreement with EAP Operating, LLC, a wholly owned subsidiary of EAC, and reduce outstanding indebtedness under our revolving credit facility.
 
Upon the closing of our IPO, Encore Operating contributed certain oil and natural gas properties and related assets in the Permian Basin in West Texas (the “Permian Basin Assets”) to us. The Permian Basin Assets are considered our predecessor and therefore, our historical results of operations include the results of operations of the Permian Basin Assets for all periods presented. In March 2007, we acquired certain oil and natural gas properties and related assets in the Elk Basin in Wyoming and Montana (the “Elk Basin Assets”) from an independent energy company. The results of operations of the Elk Basin Assets have been included with ours from the date of acquisition forward.
 
In February 2008, we acquired the Permian and Williston Basin Assets from Encore Operating. In January 2009, we acquired the Arkoma Basin Assets from Encore Operating. In June 2009, we acquired the Williston Basin Assets from Encore Operating. In August 2009, we acquired the Rockies and Permian Basin Assets from Encore Operating. Because these assets were acquired from an affiliate, the acquisitions were accounted for as transactions between entities under common control, similar to a pooling of interests, whereby the assets and liabilities of the acquired properties were recorded at Encore Operating’s carrying value and our historical financial information was recast to include the acquired properties for all periods in which the properties were owned by Encore Operating. Accordingly, our consolidated financial statements reflect our historical results combined with those of the Permian and Williston Basin Assets, the Arkoma Basin Assets, the Williston Basin Assets, and the Rockies and Permian Basin Assets.
 
At December 31, 2009, our oil and natural gas properties had estimated total proved reserves of 28.9 MMBbls of oil and 84.7 Bcf of natural gas, based on 2009 12-month average market prices of $61.18 per Bbl of oil and $3.83 per Mcf of natural gas. On a BOE basis, our proved reserves were 43.0 MMBOE at December 31, 2009, of which approximately 67 percent was oil, approximately 92 percent was proved developed, and approximately eight percent was proved undeveloped.
 
Our financial results and ability to generate cash depend upon many factors, particularly the price of oil and natural gas. Average NYMEX prices deteriorated significantly in 2009. Our oil wellhead differentials to NYMEX deteriorated slightly in 2009 as we realized 88 percent of the average NYMEX oil price, as compared to 90 percent in 2008. Our natural gas wellhead differentials to NYMEX deteriorated slightly in 2009 as we realized 92 percent of the average NYMEX natural gas price in 2009, as compared to 96 percent in 2008. Commodity prices are influenced by many factors that are outside our control. We cannot accurately predict future commodity prices. For this reason, we attempt to mitigate commodity price risk by entering into commodity derivative contracts for a portion of our forecasted production. For a discussion of factors that influence commodity prices and risks associated with our commodity derivative contracts, please read “Item 1A. Risk Factors.”
 
2009 Highlights
 
Our financial and operating results for 2009 included the following:
 
  •  In August, we acquired the Rockies and Permian Basin Assets from Encore Operating for approximately $179.6 million in cash.
 
  •  In July, we issued 9,430,000 common units at a price to the public of $14.30 per common unit. We used the net proceeds of approximately $129.2 million to fund a portion of the purchase price of the Rockies and Permian Basin Assets.
 
  •  In June, we acquired the Williston Basin Assets from Encore Operating for approximately $25.2 million in cash.
 
  •  In May, we acquired certain natural gas properties in the Vinegarone Field in Val Verde County, Texas (the “Vinegarone Assets”) from an independent energy company for approximately $27.5 million in


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  cash. Our historical results of operations, reserve data, and other operating and financial information only include information related to the Vinegarone Assets from the date of acquisition forward.
 
  •  In May, we issued 2,760,000 common units at a price to the public of $15.60 per common unit. We used the net proceeds of approximately $40.9 million to fund the purchase price of the Vinegarone Assets and a portion of the purchase price of the Williston Basin Assets.
 
  •  In January, we acquired the Arkoma Basin Assets from Encore Operating for approximately $46.4 million in cash.
 
  •  We invested $40.7 million in oil and natural gas activities, of which $8.4 million was invested in development, exploitation, and exploration activities, yielding 15 gross (1.8 net) productive wells, and $32.3 million was invested in acquisitions, primarily related to our Vinegarone Assets.
 
Results of Operations
 
Comparison of 2009 to 2008
 
Revenues.  The following table provides the components of our revenues for the periods indicated, as well as each period’s respective production volumes and average prices:
 
                                 
    Year Ended December 31,     Decrease  
    2009     2008     $     %  
 
Revenues (in thousands):
                               
Oil
  $ 127,611     $ 226,613     $ (99,002 )     (44 )%
Natural gas
    22,428       53,944       (31,516 )     (58 )%
                                 
Total oil and natural gas revenues
    150,039       280,557       (130,518 )     (47 )%
Marketing
    478       5,324       (4,846 )     (91 )%
                                 
Total revenues
  $ 150,517     $ 285,881     $ (135,364 )     (47 )%
                                 
Averaged realized prices:
                               
Oil ($/Bbl)
  $ 54.61     $ 89.45     $ (34.84 )     (39 )%
Natural gas ($/Mcf)
  $ 3.68     $ 8.67     $ (4.99 )     (58 )%
Combined ($/BOE)
  $ 44.75     $ 78.59     $ (33.84 )     (43 )%
Total production volumes:
                               
Oil (MBbls)
    2,337       2,533       (196 )     (8 )%
Natural gas (MMcf)
    6,097       6,219       (122 )     (2 )%
Combined (MBOE)
    3,353       3,570       (217 )     (6 )%
Average daily production volumes:
                               
Oil (Bbls/D)
    6,402       6,922       (520 )     (8 )%
Natural gas (Mcf/D)
    16,703       16,991       (288 )     (2 )%
Combined (BOE/D)
    9,186       9,754       (568 )     (6 )%
Average NYMEX prices:
                               
Oil (per Bbl)
  $ 61.95     $ 99.75     $ (37.80 )     (38 )%
Natural gas (per Mcf)
  $ 3.99     $ 9.04     $ (5.05 )     (56 )%
 
Oil revenues decreased 44 percent from $226.6 million in 2008 to $127.6 million in 2009 as a result of a $34.84 per Bbl decrease in our average realized oil price and a 196 MBbls decrease in our oil production volumes. Our lower average realized oil price decreased oil revenues by approximately $81.4 million and was primarily due to a lower average NYMEX price, which decreased from $99.75 per Bbl in 2008 to $61.95 per


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Bbl in 2009. Our lower oil production volumes decreased oil revenues by approximately $17.6 million and was primarily due to natural production declines in our Elk Basin field.
 
Natural gas revenues decreased 58 percent from $53.9 million in 2008 to $22.4 million in 2009 as a result of a $4.99 per Mcf decrease in our average realized natural gas price and a 122 MMcf decrease in our natural gas production volumes. Our lower average realized natural gas price decreased natural gas revenues by approximately $30.5 million and was primarily due to a lower average NYMEX price, which decreased from $9.04 per Mcf in 2008 to $3.99 per Mcf in 2009. Our lower natural gas production volumes decreased natural gas revenues by approximately $1.1 million and was primarily due to natural production declines in our Crockett County properties.
 
The following table shows the relationship between our average oil and natural gas realized prices as a percentage of average NYMEX prices for the periods indicated. Management uses the realized price to NYMEX margin analysis to analyze trends in our oil and natural gas revenues.
 
                 
    Year Ended December 31,  
    2009     2008  
 
Average realized oil price ($/Bbl)
  $ 54.61     $ 89.45  
Average NYMEX ($/Bbl)
  $ 61.95     $ 99.75  
Differential to NYMEX
  $ (7.34 )   $ (10.30 )
Average realized oil price to NYMEX percentage
    88 %     90 %
Average realized natural gas price ($/Mcf)
  $ 3.68     $ 8.67  
Average NYMEX ($/Mcf)
  $ 3.99     $ 9.04  
Differential to NYMEX
  $ (0.31 )   $ (0.37 )
Average realized natural gas price to NYMEX percentage
    92 %     96 %
 
Our average realized oil price as a percentage of the average NYMEX was 88 percent for 2009 as compared to 90 percent for 2008.
 
Our average realized natural gas price as a percentage of the average NYMEX price was 92 percent for 2009 as compared to 96 percent for 2008. The natural gas index prices related to our West Texas natural gas contracts widened in their relationship to NYMEX causing a larger differential in 2009.
 
Marketing revenues decreased 91 percent from $5.3 million in 2008 to $0.5 million in 2009 primarily as a result of a reduction in natural gas throughput in our Wildhorse pipeline. Natural gas volumes are purchased from numerous gas producers at the inlet of the pipeline and resold downstream to various local and off-system markets.


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Expenses.  The following table summarizes our expenses for the periods indicated:
 
                                 
    Year Ended December 31,     Increase/ (Decrease)  
    2009     2008     $     %  
 
Expenses (in thousands):
                               
Production:
                               
Lease operating
  $ 41,676     $ 44,752     $ (3,076 )        
Production, ad valorem, and severance taxes
    16,099       28,147       (12,048 )        
                                 
Total production expenses
    57,775       72,899       (15,124 )     (21 )%
Other:
                               
Depletion, depreciation, and amortization
    56,757       57,537       (780 )        
Exploration
    3,132       196       2,936          
General and administrative
    11,375       16,605       (5,230 )        
Marketing
    302       5,466       (5,164 )        
Derivative fair value loss (gain)
    47,464       (96,880 )     144,344          
Other operating
    3,099       1,670       1,429          
                                 
Total operating
    179,904       57,493       122,411       213 %
Interest
    10,974       6,969       4,005          
Income tax provision
    14       762       (748 )        
                                 
Total expenses
  $ 190,892     $ 65,224     $ 125,668       193 %
                                 
Expenses (per BOE):
                               
Production:
                               
Lease operating
  $ 12.43     $ 12.54     $ (0.11 )        
Production, ad valorem, and severance taxes
    4.80       7.88       (3.08 )        
                                 
Total production expenses
    17.23       20.42       (3.19 )     (16 )%
Other:
                               
Depletion, depreciation, and amortization
    16.93       16.12       0.81          
Exploration
    0.93       0.05       0.88          
General and administrative
    3.39       4.65       (1.26 )        
Marketing
    0.09       1.53       (1.44 )        
Derivative fair value loss (gain)
    14.16       (27.14 )     41.30          
Other operating
    0.92       0.47       0.45          
                                 
Total operating
    53.65       16.10       37.55       233 %
Interest
    3.27       1.95       1.32          
Income tax provision
          0.21       (0.21 )        
                                 
Total expenses
  $ 56.92     $ 18.26     $ 38.66       212 %
                                 
 
Production expenses.  Total production expenses decreased 21 percent from $72.9 million in 2008 to $57.8 million in 2009. Our production margin decreased 125 percent from $207.7 million in 2008 to $92.3 million in 2009. Total oil and natural gas wellhead revenues per BOE decreased by 43 percent and total production expenses per BOE decreased by 16 percent. On a per BOE basis, our production margin decreased 108 percent to $27.52 per BOE in 2009 as compared to $58.17 per BOE in 2008.


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ENCORE ENERGY PARTNERS LP
 
Production expense attributable to LOE decreased $3.1 million from $44.8 million in 2008 to $41.7 million in 2009 as a result of a lower production volumes and a $0.11 decrease in the per BOE rate. Our lower production volumes decreased LOE by approximately $2.7 million. Our lower average LOE per BOE rate decreased LOE by approximately $0.3 million and was primarily due to lower prices paid to oilfield service companies and suppliers and decreases in natural gas prices resulting in lower electricity costs and gas plant fuel costs.
 
Production expense attributable to production taxes decreased $12.0 million from $28.1 million in 2008 to $16.1 million in 2009 primarily due to lower wellhead revenues, which exclude the effects of commodity derivative contracts. As a percentage of wellhead revenues, production taxes increased to 10.7 percent in 2009 as compared to 10.0 percent in 2008 primarily due to higher ad valorem taxes, which are based on production volumes as opposed to a percentage of wellhead revenues.
 
Depletion, depreciation, and amortization (“DD&A”) expense.  DD&A expense decreased $0.8 million from $57.5 million in 2008 to $56.8 million in 2009, as a result of a 217 MBOE decrease in production volumes, partially offset by a $0.81 increase in the per BOE rate. Our lower production volumes decreased DD&A expense by approximately $3.5 million. Our higher average DD&A per BOE rate increased DD&A expense by approximately $2.7 million and was primarily due to the decrease in our proved reserves at the beginning of 2009 as a result of lower average commodity prices.
 
Exploration expense.  Exploration expense increased $2.9 million from $0.2 million in 2008 to $3.1 million in 2009. During 2009, we expensed 1.0 net exploratory dry hole totaling $3.0 million. No dry holes were expensed in 2008.
 
General and administrative (“G&A”) expense.  G&A expense decreased $5.2 million from $16.6 million in 2008 to $11.4 million 2009 primarily due to a decrease in non-cash equity-based compensation expense.
 
Marketing expense.  Marketing expense decreased $5.2 million from $5.5 million in 2008 to $0.3 million in 2008 as a result of a reduction in natural gas throughput in our Wildhorse pipeline. Natural gas volumes are purchased from numerous gas producers at the inlet of the pipeline and resold downstream to various local and off-system markets.
 
Derivative fair value loss (gain).  During 2009, we recorded a $47.5 million derivative fair value loss as compared to a $96.9 million derivative fair value gain in 2008, the components of which were as follows:
 
                         
    Year Ended December 31,     Increase /
 
    2009     2008     (Decrease)  
    (In thousands)  
 
Ineffectiveness
  $ 2     $ 372     $ (370 )
Mark-to-market loss (gain)
    94,438       (101,595 )     196,033  
Premium amortization
    23,245       8,936       14,309  
Settlements
    (70,221 )     (4,593 )     (65,628 )
                         
Total derivative fair value loss (gain)
  $ 47,464     $ (96,880 )   $ 144,344  
                         
 
Interest expense.  Interest expense increased $4.0 million from $7.0 million in 2008 to $11.0 million in 2009 primarily due to higher weighted average outstanding borrowings under our revolving credit facility and an increase in LIBOR. Our weighted average interest rate for 2009 was 5.0 percent as compared to 4.8 percent for 2008.


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ENCORE ENERGY PARTNERS LP
 
Comparison of 2008 to 2007
 
Revenues.  The following table provides the components of our revenues for the periods indicated, as well as each period’s respective production volumes and average prices:
 
                                 
    Year Ended December 31,     Increase/ (Decrease)  
    2008     2007     $     %  
 
Revenues (in thousands):
                               
Oil
  $ 226,613     $ 135,546     $ 91,067       67 %
Natural gas
    53,944       39,119       14,825       38 %
                                 
Total oil and natural gas revenues
    280,557       174,665       105,892       61 %
Marketing
    5,324       8,582       (3,258 )     (38 )%
                                 
Total revenues
  $ 285,881     $ 183,247     $ 102,634       56 %
                                 
Averaged realized prices:
                               
Oil ($/Bbl)
  $ 89.45     $ 60.74     $ 28.71       47 %
Natural gas ($/Mcf)
  $ 8.67     $ 6.80     $ 1.87       28 %
Combined ($/BOE)
  $ 78.59     $ 54.75     $ 23.84       44 %
Total production volumes:
                               
Oil (MBbls)
    2,533       2,232       301       13 %
Natural gas (MMcf)
    6,219       5,751       468       8 %
Combined (MBOE)
    3,570       3,190       380       12 %
Average daily production volumes:
                               
Oil (Bbl/D)
    6,922       6,114       808       13 %
Natural gas (Mcf/D)
    16,991       15,756       1,235       8 %
Combined (BOE/D)
    9,754       8,740       1,014       12 %
Average NYMEX prices:
                               
Oil (per Bbl)
  $ 99.75     $ 72.45     $ 27.30       38 %
Natural gas (per Mcf)
  $ 9.04     $ 6.86     $ 2.18       32 %
 
Oil revenues increased 67 percent from $135.5 million in 2007 to $226.6 million in 2008 as a result of higher average realized oil prices, which increased oil revenues by approximately $72.7 million, and higher oil production volumes of 301 MBbls, which increased oil revenues by approximately $18.3 million. Our average realized oil price increased $28.71 per Bbl from 2007 to 2008 primarily as a result of the increase in the average NYMEX price from $72.45 per Bbl for 2007 to $99.75 per Bbl for 2008. The increase in oil production volumes was primarily due to a full year of production from our Elk Basin Assets, which were acquired in March 2007. For 2008, approximately 49 percent of our oil production was from our Elk Basin Assets.
 
Natural gas revenues increased 38 percent from $39.1 million in 2007 to $53.9 million in 2008 as a result of higher average realized natural gas prices, which increased natural gas revenues by approximately $11.6 million, and higher natural gas production volumes of 468 MMcf, which increased natural gas revenues by approximately $3.2 million. Our average realized natural gas price increased $1.87 per Mcf from 2007 to 2008 primarily as a result of the increase in the average NYMEX price from $6.86 per Mcf for 2007 to $9.04 per Mcf for 2008. The increase in natural gas production volumes was primarily due to wells drilled in the Permian Basin during the second half of 2007 and the first half of 2008.


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ENCORE ENERGY PARTNERS LP
 
The following table shows the relationship between our average oil and natural gas realized prices as a percentage of average NYMEX prices for the periods indicated:
 
                 
    Year Ended December 31,  
    2008     2007  
 
Average realized oil price ($/Bbl)
  $ 89.45     $ 60.74  
Average NYMEX ($/Bbl)
  $ 99.75     $ 72.45  
Differential to NYMEX
  $ (10.30 )   $ (11.71 )
Average realized oil price to NYMEX percentage
    90 %     84 %
Average realized natural gas price ($/Mcf)
  $ 8.67     $ 6.80  
Average NYMEX ($/Mcf)
  $ 9.04     $ 6.86  
Differential to NYMEX
  $ (0.37 )   $ (0.06 )
Average realized natural gas price to NYMEX percentage
    96 %     99 %
 
Our average realized oil price as a percentage of the average NYMEX price improved to 90 percent for 2008 from 84 percent for 2007 as a result of improved pricing in the Rocky Mountain area. Our average realized natural gas price as a percentage of the average NYMEX price deteriorated slightly to 96 percent for 2008 from 99 percent for 2007.
 
Marketing revenues decreased 38 percent from $8.6 million in 2007 to $5.3 million in 2008 primarily as a result of a reduction in natural gas throughput in our Wildhorse pipeline. In March 2007, ENP acquired a natural gas pipeline from Anadarko as part of the Big Horn Basin asset acquisition. Natural gas volumes are purchased from numerous gas producers at the inlet of the pipeline and resold downstream to various local and off-system markets.


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ENCORE ENERGY PARTNERS LP
 
Expenses.  The following table summarizes our expenses for the periods indicated:
 
                                 
          Increase/
 
    Year Ended December 31,     (Decrease)  
    2008     2007     $     %  
 
Expenses (in thousands):
                               
Production:
                               
Lease operating
  $ 44,752     $ 33,980     $ 10,772          
Production, ad valorem, and severance taxes
    28,147       17,712       10,435          
                                 
Total production expenses
    72,899       51,692       21,207       41 %
Other:
                               
Depletion, depreciation, and amortization
    57,537       47,494       10,043          
Exploration
    196       126       70          
General and administrative
    16,605       15,245       1,360          
Marketing
    5,466       6,673       (1,207 )        
Derivative fair value loss (gain)
    (96,880 )     26,301       (123,181 )        
Other operating
    1,670       1,426       244          
                                 
Total operating
    57,493       148,957       (91,464 )     (61 )%
Interest
    6,969       12,702       (5,733 )        
Income tax provision
    762       78       684          
                                 
Total expenses
  $ 65,224     $ 161,737     $ (96,513 )     (60 )%
                                 
Expenses (per BOE):
                               
Production:
                               
Lease operating
  $ 12.54     $ 10.65     $ 1.89          
Production, ad valorem, and severance taxes
    7.88       5.55       2.33          
                                 
Total production expenses
    20.42       16.20       4.22       26 %
Other:
                               
Depletion, depreciation, and amortization
    16.12       14.89       1.23          
Exploration
    0.05       0.04       0.01          
General and administrative
    4.65       4.78       (0.13 )        
Marketing
    1.53       2.09       (0.56 )        
Derivative fair value loss
    (27.14 )     8.24       (35.38 )        
Other operating
    0.47       0.45       0.02          
                                 
Total operating
    16.10       46.69       (30.59 )     (66 )%
Interest
    1.95       3.98       (2.03 )        
Income tax provision
    0.21       0.02       0.19          
                                 
Total expenses
  $ 18.26     $ 50.69     $ (32.43 )     (64 )%
                                 
 
Production expenses.  Total production expenses increased 41 percent from $51.7 million in 2007 to $72.9 million in 2008 as a result of higher production volumes and an increase in the per BOE rate. Our production margin increased by $84.7 million (69 percent) to $207.7 million for 2008 as compared to $123.0 million for 2007. On a per BOE basis, our production margin increased 51 percent to $58.17 per BOE for 2008 as compared to $38.55 per BOE for 2007. Total oil and natural gas revenues per BOE increased by 44 percent while total production expenses per BOE increased by 26 percent.


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ENCORE ENERGY PARTNERS LP
 
Production expense attributable to LOE increased $10.8 million from $34.0 million in 2007 to $44.8 million in 2008 as a result of a $1.89 increase in the average per BOE rate, which contributed approximately $6.8 million of additional LOE, and an increase in production volumes, which contributed approximately $4.0 million of additional LOE. The increase in our average LOE per BOE rate was primarily due to the increase in natural gas prices and increases in prices paid to oilfield service companies and suppliers. In West Texas, the higher gas prices increased the electrical rates charged to our producing properties, and at the Elk Basin gas plant, the charges associated with the fuel gas were also higher.
 
Production taxes increased $10.4 million from $17.7 million in 2007 to $28.1 million in 2008 primarily due to higher wellhead revenues. As a percentage of wellhead revenues, production taxes remained approximately constant at 10.0 percent for 2008 as compared to 10.1 percent in 2007.
 
DD&A expense.  DD&A expense increased $10.0 million from $47.5 million in 2007 to $57.5 million in 2008 as a result of higher production volumes, which contributed approximately $5.7 million of additional DD&A expense, and an increase in the per BOE rate of $1.23, which contributed approximately $4.4 million of additional DD&A expense. The increase in our average DD&A per BOE rate was primarily due to higher costs incurred resulting from increases in rig rate, pipe costs, and acquisition costs, and the decrease in our total proved reserves to 40.3 MMBOE as of December 31, 2008 as compared to 49.1 MMBOE as of December 31, 2007.
 
G&A expense.  G&A expense increased $1.4 million from $15.2 million in 2007 to $16.6 million primarily due to a higher per BOE rate allocated by EAC to the Rockies and Permian Basin Operations than our historical per BOE rate.
 
Marketing expense.  Marketing expense decreased $1.2 million from $6.7 million in 2007 to $5.5 million in 2008 as a result of a reduction in natural gas throughput in our Wildhorse pipeline. In March 2007, ENP acquired a natural gas pipeline from Anadarko as part of the Big Horn Basin asset acquisition. Natural gas volumes are purchased from numerous gas producers at the inlet of the pipeline and resold downstream to various local and off-system markets.
 
Derivative fair value loss (gain).  During 2008, we recorded a $96.9 million derivative fair value gain as compared to a $26.3 million loss in 2007, the components of which were as follows:
 
                         
    Year Ended December 31,     Increase /
 
    2008     2007     (Decrease)  
    (In thousands)  
 
Ineffectiveness
  $ 372     $     $ 372  
Mark-to-market loss (gain)
    (101,595 )     23,470       (125,065 )
Premium amortization
    8,936       4,073       4,863  
Settlements
    (4,593 )     (1,242 )     (3,351 )
                         
Total derivative fair value loss (gain)
  $ (96,880 )   $ 26,301     $ (123,181 )
                         
 
Interest expense.  Interest expense decreased $5.7 million from $12.7 million in 2007 to $7.0 million in 2009, primarily due to (1) the use of net proceeds from our IPO to reduce weighted average outstanding borrowings on our revolving credit facility and subordinated credit agreement, (2) a reduction in LIBOR, and (3) our use of interest rate swaps to fix the rate on a portion of outstanding borrowings on our revolving credit facility. Our weighted average interest rate for 2008 was 4.8 percent as compared to 8.9 percent for 2007.
 
Capital Commitments, Capital Resources, and Liquidity
 
Capital commitments.  Our primary uses of cash are:
 
  •  Distributions to unitholders;
 
  •  Development, exploitation, and exploration of oil and natural gas properties;


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ENCORE ENERGY PARTNERS LP
 
 
  •  Acquisitions of oil and natural gas properties;
 
  •  Funding of working capital; and
 
  •  Contractual obligations.
 
Distributions to unitholders.  Our partnership agreement requires that, within 45 days after the end of each quarter, we distribute all of our available cash (as defined in the partnership agreement). Our available cash is our cash on hand at the end of a quarter after the payment of our expenses and the establishment of reserves for future capital expenditures and operational needs. During 2009, 2008, and 2007, we distributed $81.7 million, $74.4 million, and $1.3 million, respectively, to our unitholders.
 
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. 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.
 
Development, exploitation, and exploration of oil and natural gas properties.  The following table summarizes our costs incurred related to development, exploitation, and exploration activities for the periods indicated:
 
                         
    Year Ended December 31,  
    2009     2008     2007  
    (In thousands)  
 
Development and exploitation
  $ 7,197     $ 31,450     $ 21,277  
Exploration
    1,223       8,223       10,000  
                         
Total
  $ 8,420     $ 39,673     $ 31,277  
                         
 
Our development and exploitation expenditures primarily relate to drilling development and infill wells, workovers of existing wells, and field related facilities. Our development and exploitation capital for 2009 yielded 9 gross (1.2 net) productive wells and no dry holes. Our exploration expenditures primarily relate to drilling exploratory wells, seismic costs, delay rentals, and geological and geophysical costs. Our exploration capital for 2009 yielded 6 gross (0.6 net) productive wells and 1 gross (1.0 net) dry hole. Please read “Items 1 and 2. Business and Properties — Development Results” for a description of the areas in which we drilled wells during 2009.
 
Acquisitions of oil and natural gas properties and leasehold acreage.  The following table summarizes our costs incurred related to oil and natural gas property acquisitions for the periods indicated:
 
                         
    Year Ended December 31,  
    2009     2008     2007  
    (In thousands)  
 
Acquisitions of proved property
  $ 32,265     $ 5,940     $ 498,057  
Acquisitions of leasehold acreage
    1             105  
                         
Total
  $ 32,266     $ 5,940     $ 498,162  
                         
 
In August 2009, we acquired the Rockies and Permian Basin Assets from Encore Operating for approximately $179.6 million in cash. In June 2009, we acquired the Williston Basin Assets from Encore


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ENCORE ENERGY PARTNERS LP
 
Operating for approximately $25.2 million in cash. In January 2009, we acquired the Arkoma Basin Assets from Encore Operating for approximately $46.4 million in cash. In February 2008, we acquired the Permian and Williston Basin Assets from Encore Operating for total consideration of approximately $125.0 million in cash and the issuance of 6,884,776 ENP common units to Encore Operating. In determining the total purchase price, the common units were valued at $125.0 million. However, no accounting value was ascribed to the common units as the cash consideration exceeded Encore Operating’s carrying value of the properties. Because these assets were acquired from an affiliate, the acquisitions were accounted for as transactions between entities under common control, similar to a pooling of interests, whereby the assets and liabilities of the acquired properties were recorded at Encore Operating carrying value and our historical financial information was recast to include the acquired properties for all periods in which the properties were owned by Encore Operating.
 
In May 2009, we acquired the Vinegarone Assets from an independent energy company for approximately $27.5 million in cash. In May 2008, we acquired an existing net profits interest in certain of our proved properties in the Permian Basin in West Texas from an independent energy company for 283,700 ENP common units, which were valued at approximately $5.8 million at the time of the acquisition. In March 2007, we acquired the Elk Basin Assets from an independent energy company for approximately $330.7 million in cash. Also in March 2007, we acquired certain properties in the Gooseberry field for approximately $62.9 million. In April 2007, we acquired certain properties in the Williston Basin for approximately $102.0 million. The Gooseberry and Williston Basin properties were acquired from EAC and, as the acquisition was accounted for as a transaction between entities under common control, the purchase price of the properties are shown in the period the properties were originally purchased by EAC.
 
Funding of working capital.  As of December 31, 2009 and 2008, our working capital (defined as total current assets less total current liabilities) was $15.6 million and $71.6 million, respectively. The decrease was primarily due to higher oil prices at December 31, 2009 as compared to December 31, 2008, which negatively impacted the fair value of our outstanding oil derivative contracts.
 
For 2010, we expect working capital to remain positive primarily due to the fair value of our outstanding commodity derivative contracts. We anticipate cash reserves to be close to zero because we intend to distribute available cash to unitholders and reduce outstanding borrowings under our revolving credit facility. However, we have availability under our revolving credit facility to fund our obligations as they become due. Our production volumes, commodity prices, and differentials for oil and natural gas will be the largest variables affecting our working capital. Our operating cash flow is determined in large part by production volumes and commodity prices. Given our current commodity derivative contracts, assuming relatively stable commodity prices and constant production volumes, our operating cash flow should remain positive for 2010.
 
Our capital expenditures are largely discretionary, and the amount of funds devoted to any particular activity may increase or decrease significantly, depending on available opportunities, timing of projects, and market conditions. We plan to finance our ongoing expenditures using internally generated cash flow and availability under our revolving credit facility.
 
Off-balance sheet arrangements.  We have no investments in unconsolidated entities or persons that could materially affect our liquidity or the availability of capital resources. We have no off-balance sheet arrangements that are material to our financial position or results of operations.


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ENCORE ENERGY PARTNERS LP
 
Contractual obligations.  The following table provides our contractual obligations and commitments at December 31, 2009:
 
                                         
    Payments Due by Period  
Contractual Obligations and Commitments
  Total     2010     2011 - 2012     2013 - 2014     Thereafter  
    (In thousands)  
 
Revolving credit facility(a)
  $ 270,908     $ 7,070     $ 263,838     $     $  
Commodity derivative contracts(b)
    9,635             9,635              
Interest rate swaps(c)
    3,669       3,320       349              
Development commitments(d)
    1,536       1,536                    
Operating leases and commitments(e)
    1,888       687       1,201              
Asset retirement obligations(f)
    43,475       573       1,147       1,160       40,595  
                                         
Total
  $ 331,111     $ 13,186     $ 276,170     $ 1,160     $ 40,595  
                                         
 
 
(a) Includes principal and projected interest payments. Please read Note 6 of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information regarding our long-term debt.
 
(b) At December 31, 2009, our commodity derivative contracts were in a net asset position. Please read “Item 7A. Quantitative and Qualitative Disclosures about Market Risk” and Note 10 of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information regarding our commodity derivative contracts.
 
(c) Represents net liabilities for interest rate swaps, the ultimate settlement of which are unknown because they are subject to continuing market risk. Please read “Item 7A. Quantitative and Qualitative Disclosures about Market Risk” and Note 10 of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information regarding our interest rate swaps.
 
(d) Represents authorized purchases for work in process. Also at December 31, 2009, we had $18.3 million of authorized purchases not placed to vendors (authorized AFEs), which were not accrued and are excluded from the above table, but are budgeted for and expected to be made unless circumstances change.
 
(e) Represents equipment obligations that have non-cancelable lease terms in excess of one year. Please read Note 4 of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information regarding our operating leases.
 
(f) Represents the undiscounted future plugging and abandonment expenses on oil and natural gas properties and related facilities disposal at the end of field life. Please read Note 5 of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information regarding our asset retirement obligations.
 
Other contingencies and commitments.  Encore Operating provides administrative services for us, such as accounting, corporate development, finance, land, legal, and engineering, pursuant to an administrative services agreement. In addition, Encore Operating provides all personnel and any facilities, goods, and equipment necessary to perform these services and not otherwise provided by us. 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. Effective April 1, 2009, the administrative fee increased to $2.02 per BOE of our production as a result of the COPAS Wage Index Adjustment. We also reimburse Encore Operating for actual third-party expenses incurred on our behalf. Encore Operating has substantial discretion in determining which third-party expenses to incur on our behalf. In addition, Encore Operating 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.


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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, Encore Operating 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 Encore Operating and our general partner, with the approval of the conflicts committee of the board of directors of our general partner.
 
Capital resources
 
Cash flows from operating activities.  Cash provided by operating activities decreased $74.2 million from $189.2 million in 2008 to $115.0 million in 2009, primarily due to a decrease in our production margin, partially offset by decreased settlements on our commodity derivative contracts as a result of lower average oil prices in 2009 as compared to 2008. Cash provided by operating activities increased $115.8 million from $73.4 million in 2007 to $189.2 million in 2007, primarily due to an increase in our production margin, partially offset by increased settlements on our commodity derivative contracts as a result of higher commodity prices in the first half of 2008.
 
Cash flows from investing activities.  Cash used in investing activities decreased $1.2 million from $42.3 million in 2008 to $41.1 million in 2009, primarily due to a $32.8 million decrease in amounts paid to develop oil and natural gas properties, partially offset by a $31.7 million increase in amounts paid to acquire oil and natural gas properties, namely the Vinegarone Assets.
 
Cash used in investing activities decreased $482.5 million from $524.8 million in 2007 to $42.3 million in 2008, primarily due to a $495.0 million decrease in amounts paid for the acquisition of oil and natural gas properties, partially offset by a $12.8 million increase in amounts paid to develop oil and natural gas properties. In March 2007, we acquired the Elk Basin Assets for approximately $330.7 million. Also in March 2007, we acquired certain properties in the Gooseberry field for approximately $62.9 million. In April 2007, we acquired certain properties in the Williston Basin for approximately $102.0 million. The Gooseberry and Williston Basin properties were acquired from EAC and, as the acquisition was accounted for as a transaction between entities under common control, the purchase price of the properties are shown in the period the properties were originally purchased by EAC.
 
Cash flows from financing activities.  Our cash flows from financing activities consist primarily of proceeds from and payments on long-term debt, distributions to unitholders, and issuances of our common units. We periodically draw on our revolving credit facility to fund acquisitions and other capital commitments.
 
During 2009, we used net cash of $72.8 million in financing activities, including $251.2 million in deemed distributions to affiliates in connection with acquisitions and $81.7 million in distributions to unitholders, partially offset by $170.1 million net proceeds from the issuance of our common units and net borrowings of $105 million under our revolving credit facility. Net borrowings on our revolving credit facility resulted in an increase in outstanding borrowings under our revolving credit facility from $150 million at December 31, 2008 to $255 million at December 31, 2009.
 
During 2008, we used net cash of $146.3 million in financing activities, including $125.0 million in deemed distributions to affiliates in connection with our acquisition of the Permian and Williston Basin Assets, $74.4 million in distributions to unitholders, and $48.8 million in net distributions to EAC related to pre-partnership operations, partially offset by net borrowings of $102.5 million under our revolving credit facility. Net borrowings on our revolving credit facility resulted in an increase in outstanding borrowings under our revolving credit facility from $47.5 million at December 31, 2007 to $150 million at December 31, 2008.


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During 2007, we received net cash of $451.4 million from financing activities, including net borrowings on our long-term debt of $47.5 million, net proceeds received from the sale of our common units of $193.5 million, $93.7 million contribution from EAC used to partially finance our acquisition of the Big Horn Basin Assets, and $119.9 million of net contributions from EAC related to pre-partnership or pre-IPO operations.
 
Liquidity
 
Our primary sources of liquidity are internally generated cash flows and the borrowing capacity under our revolving credit facility. We also have the ability to adjust our capital expenditures. We may use other sources of capital, including the issuance of debt or common units, to fund acquisitions or maintain our financial flexibility. We believe that our internally generated cash flows and availability under our revolving credit facility will be sufficient to fund our planned capital expenditures for the foreseeable future. However, should commodity prices decline or the capital markets remain tight, the borrowing capacity under our revolving credit facility could be adversely affected. In the event of a reduction in the borrowing base under our revolving credit facility, we currently do not believe it will result in any required prepayments of indebtedness.
 
Our partnership agreement requires that we distribute all of our available cash quarterly. 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. 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. 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. In addition, our partnership agreement allows our general partner to borrow funds to make distributions.
 
Internally generated cash flows.  Our internally generated cash flows, results of operations, and financing for our operations are largely dependent on oil and natural gas prices. During 2009, our average realized oil and natural gas prices decreased by 39 percent and 58 percent, respectively, as compared to 2008. Realized oil and natural gas prices fluctuate widely in response to changing market forces. If oil and natural gas prices decline, or we experience a significant widening of our differentials, then our earnings, cash flows from operations, borrowing base under our revolving credit facility, and ability to pay distributions may be adversely impacted. Prolonged periods of lower oil and natural gas prices, or sustained wider differentials, could cause us to not be in compliance with financial covenants under our revolving credit facility and thereby affect our liquidity. However, we have protected approximately two-thirds of our forecasted production through 2012 against declining commodity prices.
 
Revolving credit facility.  The syndicate of lenders underwriting our revolving credit facility includes 15 banking and other financial institutions. None of the lenders are underwriting more than eight percent of the total commitments. We believe the number of lenders and the small percentage participation of each, provides adequate diversity and flexibility should further consolidation occur within the financial services industry.
 
Certain of the lenders underwriting our facility are also counterparties to our commodity derivative contracts. Please read “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” for additional discussion.


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In March 2007, OLLC entered into a five-year credit agreement (as amended, the “OLLC Credit Agreement”) with a bank syndicate including Bank of America, N.A. and other lenders. The OLLC Credit Agreement matures on March 7, 2012. In March 2009, OLLC amended the OLLC Credit Agreement to, among other things, increase the interest rate margins and commitment fees applicable to loans made under the OLLC Credit Agreement. In August 2009, OLLC amended the OLLC Credit Agreement to, among other things, (1) increase the borrowing base from $240 million to $375 million, (2) increase the aggregate commitments of the lenders from $300 million to $475 million, and (3) increase the interest rate margins and commitment fees applicable to loans made under the OLLC Credit Agreement. In November 2009, OLLC amended the OLLC Credit Agreement, which will be effective upon the closing of the Merger, to, among other things, permit the consummation of the Merger from being a “Change of Control” under the OLLC Credit Agreement.
 
The OLLC Credit Agreement provides for revolving credit loans to be made to OLLC from time to time and letters of credit to be issued from time to time for the account of OLLC or any of its restricted subsidiaries. The aggregate amount of the commitments of the lenders under the OLLC Credit Agreement is $475 million. Availability under the OLLC Credit Agreement is subject to a borrowing base, which is redetermined semi-annually and upon requested special redeterminations. As of December 31, 2009, the borrowing base was $375 million.
 
OLLC incurs a commitment fee of 0.5 percent on the unused portion of the OLLC Credit Agreement.
 
Obligations under the OLLC Credit Agreement are secured by a first-priority security interest in substantially all of OLLC’s proved oil and natural gas reserves and in the equity interests of OLLC and its restricted subsidiaries. In addition, obligations under the OLLC Credit Agreement are guaranteed by us and OLLC’s restricted subsidiaries. Obligations under the OLLC Credit Agreement are non-recourse to EAC and its restricted subsidiaries.
 
Loans under the OLLC Credit Agreement are subject to varying rates of interest based on (1) outstanding borrowings in relation to the borrowing base and (2) whether the loan is a Eurodollar loan or a base rate loan. Eurodollar loans bear interest at the Eurodollar rate plus the applicable margin indicated in the following table, and base rate loans bear interest at the base rate plus the applicable margin indicated in the following table:
 
                 
    Applicable Margin for
  Applicable Margin for
Ratio of Outstanding Borrowings to Borrowing Base
  Eurodollar Loans   Base Rate Loans
 
Less than .50 to 1
    2.250 %     1.250 %
Greater than or equal to .50 to 1 but less than .75 to 1
    2.500 %     1.500 %
Greater than or equal to .75 to 1 but less than .90 to 1
    2.750 %     1.750 %
Greater than or equal to .90 to 1
    3.000 %     2.000 %
 
The “Eurodollar rate” for any interest period (either one, two, three, or six months, as selected by us) is the rate equal to the British Bankers Association LIBOR for deposits in dollars for a similar interest period. The “Base Rate” is calculated as the highest of: (1) the annual rate of interest announced by Bank of America, N.A. as its “prime rate”; (2) the federal funds effective rate plus 0.5 percent; or (3) except during a “LIBOR Unavailability Period,” the Eurodollar rate (for dollar deposits for a one-month term) for such day plus 1.0 percent.
 
Any outstanding letters of credit reduce the availability under the OLLC Credit Agreement. Borrowings under the OLLC Credit Agreement may be repaid from time to time without penalty.
 
The OLLC Credit Agreement contains covenants including, among others, the following:
 
  •  a prohibition against incurring debt, subject to permitted exceptions;
 
  •  a prohibition against purchasing or redeeming capital stock, or prepaying indebtedness, subject to permitted exceptions;


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  •  a restriction on creating liens on our assets and the assets of our subsidiaries, subject to permitted exceptions;
 
  •  restrictions on merging and selling assets outside the ordinary course of business;
 
  •  restrictions on use of proceeds, investments, transactions with affiliates, or change of principal business;
 
  •  a provision limiting oil and natural gas hedging transactions (other than puts) to a volume not exceeding 75 percent of anticipated production from proved producing reserves;
 
  •  a requirement that we and OLLC maintain a ratio of consolidated current assets to consolidated current liabilities of not less than 1.0 to 1.0 (the “Current Ratio”);
 
  •  a requirement that we and OLLC maintain a ratio of consolidated EBITDA to the sum of consolidated net interest expense plus letter of credit fees of not less than 2.5 to 1.0 (the “Interest Coverage Ratio”); and
 
  •  a requirement that we and OLLC maintain a ratio of consolidated funded debt to consolidated adjusted EBITDA of not more than 3.5 to 1.0 (the “Leverage Ratio”).
 
In order to show our and OLLC’s compliance with the covenants of the OLLC Credit Agreement, the use of non-GAAP financial measures is required. The presentation of these non-GAAP financial measures provides useful information to investors as they allow readers to understand how much cushion there is between the required ratios and the actual ratios. These non-GAAP financial measures should not be considered an alternative to any measure of financial performance presented in accordance with GAAP.
 
As of December 31, 2009, we and OLLC were in compliance with all covenants in the OLLC Credit Agreement, including the following financial covenants:
 
                 
          Actual Ratio as of
 
          December 31,
 
Financial Covenant
  Required Ratio     2009  
 
Current Ratio
    Minimum 1.0 to 1.0       5.1 to 1.0  
Interest Coverage Ratio
    Minimum 2.5 to 1.0       10.7 to 1.0  
Leverage Ratio
    Maximum 3.5 to 1.0       2.0 to 1.0  
 
The following table shows the calculation of the Current Ratio as of December 31, 2009 ($ in thousands):
 
         
Current assets
  $ 48,248  
Availability under the OLLC Credit Agreement
    120,000  
         
Consolidated current assets
  $ 168,248  
         
Divided by: consolidated current liabilities
  $ 32,690  
Current Ratio
    5.1  
 
The following table shows the calculation of the Interest Coverage Ratio for the twelve months ended December 31, 2009 ($ in thousands):
 
         
Consolidated EBITDA(a)
  $ 116,732  
Divided by: Consolidated net interest expense and letter of credit fees
  $ 10,928  
Interest Coverage Ratio
    10.7  
 
 
(a) Consolidated EBITDA is defined in the OLLC Credit Agreement and generally means earnings before interest, income taxes, depletion, depreciation, and amortization, and exploration expense. Consolidated EBITDA is a non-GAAP financial measure, which is reconciled to its most directly comparable GAAP measure below.


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The following table shows the calculation of the Leverage Ratio for the twelve months ended December 31, 2009 ($ in thousands):
 
         
Consolidated funded debt
  $ 255,000  
Divided by: Consolidated Adjusted EBITDA(a)
  $ 127,719  
Leverage Ratio
    2.0  
 
 
(a) Consolidated Adjusted EBITDA is defined in the OLLC Credit Agreement and generally means earnings before interest, income taxes, depletion, depreciation, and amortization, and exploration expense, after giving pro forma effect to one or more acquisitions or dispositions in excess of $20 million in the aggregate. Consolidated Adjusted EBITDA is a non-GAAP financial measure, which is reconciled to its most directly comparable GAAP measure below.
 
The following table presents a calculation of Consolidated EBITDA and Consolidated Adjusted EBITDA for the twelve months ended December 31, 2009 (in thousands) as required under the OLLC Credit Agreement, together with a reconciliation of such amounts to their most directly comparable financial measures calculated and presented in accordance with GAAP. These EBITDA measures should not be considered an alternative to net income (loss), operating income (loss), cash flow from operating activities, or any other measure of financial performance or liquidity presented in accordance with GAAP. These EBITDA measures may not be comparable to similarly titled measures of another company because all companies may not calculate these measures in the same manner.
 
         
Consolidated net income
  $ (40,507 )
Unrealized non-cash hedge gain
    94,441  
Consolidated net interest expense
    10,928  
Income and franchise taxes
    14  
Depletion, depreciation, amortization, and exploration expense
    50,040  
Non-cash unit-based compensation
    565  
Other non-cash
    1,251  
         
Consolidated EBITDA
    116,732  
Pro forma effect of acquisitions
    10,987  
         
Consolidated Adjusted EBITDA
  $ 127,719  
         
 
The OLLC Credit Agreement contains customary events of default, which would permit the lenders to accelerate the debt if not cured within applicable grace periods. If an event of default occurs and is continuing, lenders with a majority of the aggregate commitments may require Bank of America, N.A. to declare all amounts outstanding under the OLLC Credit Agreement to be immediately due and payable.
 
On December 31, 2009, we had $255 million of outstanding borrowings and $120 million of borrowing capacity under the OLLC Credit Agreement. On February 17, 2010, we had $260 million of outstanding borrowings and $115 million of borrowing capacity under the OLLC Credit Agreement.
 
Capitalization.  At December 31, 2009, we had total assets of $719.7 million and total capitalization of $661.0 million, of which 61 percent was represented by partners’ equity and 39 percent by long-term debt. At December 31, 2008, we had total assets of $813.3 million and total capitalization of $769.4 million, of which 81 percent was represented by partners’ equity and 19 percent by long-term debt. The percentages of our capitalization represented by partners’ equity and long-term debt could vary in the future if debt or equity is used to finance capital projects or acquisitions.


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Changes in Prices
 
Our oil and natural gas revenues, the value of our assets, and our ability to obtain bank loans or additional capital on attractive terms are affected by changes in oil and natural gas prices, which fluctuate significantly. The following table provides our average realized oil and natural gas prices for the periods indicated:
 
                         
    Year Ended December 31,
    2009   2008   2007
 
Average realized prices:
                       
Oil ($/Bbl)
  $ 54.61     $ 89.45     $ 60.74  
Natural gas ($/Mcf)
    3.68       8.67       6.80  
Combined ($/BOE)
    44.75       78.59       54.75  
 
Increases in oil and natural gas prices may be accompanied by or result in: (1) increased development costs, as the demand for drilling operations increases; (2) increased severance taxes, as we are subject to higher severance taxes due to the increased value of oil and natural gas extracted from our wells; (3) increased LOE, as the demand for services related to the operation of our wells increases; and (4) increased electricity costs. Decreases in oil and natural gas prices may be accompanied by or result in: (1) decreased development costs, as the demand for drilling operations decreases; (2) decreased severance taxes, as we are subject to lower severance taxes due to the decreased value of oil and natural gas extracted from our wells; (3) decreased LOE, as the demand for services related to the operation of our wells decreases; (4) decreased electricity costs; (5) impairment of oil and natural gas properties; and (6) decreased revenues and cash flows. We believe our risk management program and available borrowing capacity under our revolving credit facility provide means for us to manage commodity price risks.
 
Critical Accounting Policies and Estimates
 
Preparing financial statements in accordance with GAAP requires management to make certain estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, and expenses, and related disclosures. Management considers an accounting estimate to be critical if it requires assumptions to be made that were uncertain at the time the estimate was made, and changes in the estimate or different estimates that could have been selected, could have a material impact on our consolidated results of operations or financial condition. Management has identified the following critical accounting policies and estimates.
 
Oil and Natural Gas Properties
 
Successful efforts method.  We use the successful efforts method of accounting for oil and natural gas properties under ASC 932 (formerly SFAS No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies”). Under this method, all costs associated with productive and nonproductive development wells are capitalized. Exploration expenses, including geological and geophysical expenses and delay rentals, are charged to expense as incurred. Costs associated with drilling exploratory wells are initially capitalized pending determination of whether the well is economically productive or nonproductive.
 
If an exploratory well does not find reserves or does not find reserves in a sufficient quantity as to make them economically producible, the previously capitalized costs would be expensed in the period in which the determination was made. If an exploratory well finds reserves but they cannot be classified as proved, we continue to capitalize the associated cost as long as the well has found a sufficient quantity of reserves to justify its completion as a producing well and we are making sufficient progress in assessing the reserves and the operating viability of the project. If subsequently it is determined that these conditions do not continue to exist, all previously capitalized costs associated with the exploratory well are expensed in the period in which the determination was made. Re-drilling or directional drilling in a previously abandoned well is classified as development or exploratory based on whether it is in a proved or unproved reservoir. Costs for repairs and maintenance to sustain or increase production from the existing producing reservoir are charged to expense as


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incurred. Costs to recomplete a well in a different unproved reservoir are capitalized pending determination that economic reserves have been added. If the recompletion is unsuccessful, the costs are charged to expense.
 
DD&A expense is directly affected by our reserve estimates. Significant revisions to reserve estimates can be and are made by our reserve engineers each year. Mostly these are the result of changes in price, but as reserve quantities are estimates, they can also change as more or better information is collected, especially in the case of estimates in newer fields. Downward revisions have the effect of increasing our DD&A rate, while upward revisions have the effect of decreasing our DD&A rate. Assuming no other changes, such as an increase in depreciable base, as our reserves increase, the amount of DD&A expense in a given period decreases and vice versa. DD&A expense associated with lease and well equipment and intangible drilling costs is based upon proved developed reserves, while DD&A expense for capitalized leasehold costs is based upon total proved reserves. As a result, changes in the classification of our reserves could have a material impact on our DD&A expense.
 
Miller and Lents estimates our reserves annually on December 31. This results in a new DD&A rate which we use for the preceding fourth quarter after adjusting for fourth quarter production. We internally estimate reserve additions and reclassifications of reserves from proved undeveloped to proved developed at the end of the first, second, and third quarters for use in determining a DD&A rate for the respective quarter.
 
Significant tangible equipment added or replaced that extends the useful or productive life of the property is capitalized. Costs to construct facilities or increase the productive capacity from existing reservoirs are capitalized. Capitalized costs are amortized on a unit-of-production basis over the remaining life of proved developed reserves or total proved reserves, as applicable. Natural gas volumes are converted to BOE at the rate of six Mcf of natural gas to one Bbl of oil.
 
The costs of retired, sold, or abandoned properties that constitute part of an amortization base are charged or credited, net of proceeds received, to accumulated DD&A.
 
In accordance with ASC 360-10, 205, 840, 958, and 855-10-60-1 (formerly SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets”), we assess the need for an impairment of long-lived assets to be held and used, including proved oil and natural gas properties, whenever events and circumstances indicate that the carrying value of the asset may not be recoverable. If impairment is indicated based on a comparison of the asset’s carrying value to its undiscounted expected future net cash flows, then an impairment charge is recognized to the extent the asset’s carrying value exceeds its fair value. Expected future net cash flows are based on existing proved reserves (and appropriately risk-adjusted probable reserves), forecasted production information, and management’s outlook of future commodity prices. Any impairment charge incurred is expensed and reduces our net basis in the asset. Management aggregates proved property for impairment testing the same way as for calculating DD&A. The price assumptions used to calculate undiscounted cash flows is based on judgment. We use prices consistent with the prices we believe a market participant would use in bidding on acquisitions and/or assessing capital projects. These price assumptions are critical to the impairment analysis as lower prices could trigger impairment.
 
Unproved properties, the majority of which relate to the acquisition of leasehold interests, are assessed for impairment on a property-by-property basis for individually significant balances and on an aggregate basis for individually insignificant balances. If the assessment indicates impairment, a loss is recognized by providing a valuation allowance at the level at which impairment was assessed. The impairment assessment is affected by economic factors such as the results of exploration activities, commodity price outlooks, remaining lease terms, and potential shifts in business strategy employed by management. In the case of individually insignificant balances, the amount of the impairment loss recognized is determined by amortizing the portion of the unproved properties’ costs which we believe will not be transferred to proved properties over the life of the lease. One of the primary factors in determining what portion will not be transferred to proved properties is the relative proportion of the unproved properties on which proved reserves have been found in the past. Since wells drilled on unproved acreage are inherently exploratory in nature, actual results could vary from estimates especially in newer areas in which we do not have a long history of drilling.


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Oil and natural gas reserves.  Our estimates of proved reserves are based on the quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward from known reservoirs under existing conditions and operating methods. Miller and Lents prepares a reserve and economic evaluation of all of our properties on a well-by-well basis. Assumptions used by Miller and Lents in calculating reserves or regarding the future cash flows or fair value of our properties are subject to change in the future. The accuracy of reserve estimates is a function of the:
 
  •  quality and quantity of available data;
 
  •  interpretation of that data;
 
  •  accuracy of various mandated economic assumptions; and
 
  •  judgment of the independent reserve engineer.
 
Future prices received for production and future production costs may vary, perhaps significantly, from the prices and costs assumed for purposes of calculating reserve estimates. We may not be able to develop proved reserves within the periods estimated. Furthermore, prices and costs may not remain constant. Actual production may not equal the estimated amounts used in the preparation of reserve projections. As these estimates change, calculated reserves change. Any change in reserves directly impacts our estimate of future cash flows from the property, the property’s fair value, and our DD&A rate.
 
Asset retirement obligations.  In accordance with ASC 410-20, 450-20, 835-20, 360-10-35, 840-10, and 980-410 (formerly SFAS No. 143, “Accounting for Asset Retirement Obligations”), we recognize the fair value of a liability for an asset retirement obligation in the period in which the liability is incurred. For oil and natural gas properties, this is the period in which an oil or natural gas property is acquired or a new well is drilled. An amount equal to and offsetting the liability is capitalized as part of the carrying amount of our oil and natural gas properties. The liability is recorded at its discounted risk adjusted fair value and then accreted each period until it is settled or the asset is sold, at which time the liability is reversed.
 
The fair value of the liability associated with the asset retirement obligation is determined using significant assumptions, including current estimates of the plugging and abandonment costs, annual expected inflation of these costs, the productive life of the asset, and our credit-adjusted risk-free interest rate used to discount the expected future cash flows. Changes in any of these assumptions can result in significant revisions to the estimated asset retirement obligation. Revisions to the obligation are recorded with an offsetting change to the carrying amount of the related oil and natural gas properties, resulting in prospective changes to DD&A and accretion expense. Because of the subjectivity of assumptions and the relatively long life of most of our oil and natural gas properties, the costs to ultimately retire these assets may vary significantly from our estimates.
 
Goodwill and Other Intangible Assets
 
We account for goodwill and other intangible assets under the provisions of ASC 350, 730-10-60-3, 323-10-35-13, 205-20-60-4, and 280-10-60-2 (formerly SFAS No. 142, “Goodwill and Other Intangible Assets”). Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in business combinations. Goodwill is assessed for impairment annually on December 31 or whenever indicators of impairment exist. The goodwill test is performed at the reporting unit level. We have determined that we have only one reporting unit, which is oil and natural gas production in the United States. If indicators of impairment are determined to exist, an impairment charge is recognized for the amount by which the carrying value of goodwill exceeds its implied fair value.
 
We utilize both a market capitalization and an income approach to determine the fair value of our reporting units. The primary component of the income approach is the estimated discounted future net cash flows expected to be recovered from the reporting unit’s oil and natural gas properties. Our analysis concluded


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that there was no impairment of goodwill as of December 31, 2009. Any sharp decreases in the prices of oil and natural gas or any significant negative reserve adjustments from the December 31, 2009 assessment could change our estimates of the fair value of our reporting units and could result in an impairment charge.
 
Intangible assets with definite useful lives are amortized over their estimated useful lives. In accordance with ASC 360-10, 205, 840, 958, and 855-10-60-1, we evaluate the recoverability of intangible assets with definite useful lives whenever events or changes in circumstances indicate that the carrying value of the asset may not be fully recoverable. An impairment loss exists when the estimated undiscounted cash flows expected to result from the use of the asset and its eventual disposition are less than its carrying amount.
 
We allocate the purchase price paid for the acquisition of a business to the assets and liabilities acquired based on the estimated fair values of those assets and liabilities. Estimates of fair value are based upon, among other things, reserve estimates, anticipated future prices and costs, and expected net cash flows to be generated. These estimates are often highly subjective and may have a material impact on the amounts recorded for acquired assets and liabilities.
 
Oil and Natural Gas Revenue Recognition
 
Oil and natural gas revenues are recognized as oil and natural gas is produced and sold, net of royalties. Royalties and severance taxes are incurred based upon the actual price received from the sales. To the extent actual volumes and prices of oil and natural gas sales are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volumes and prices for those properties are estimated and recorded. Natural gas revenues are reduced by any processing and other fees incurred except for transportation costs paid to third parties, which are recorded as expense. Natural gas revenues are recorded using the sales method of accounting whereby revenue is recognized based on our actual sales of natural gas rather than our proportionate share of natural gas production. If our overproduced imbalance position (i.e., we have cumulatively been over-allocated production) is greater than our share of remaining reserves, a liability is recorded for the excess at period-end prices unless a different price is specified in the contract in which case that price is used. Revenue is not recognized for production in tanks, oil marketed on behalf of joint interest owners in our properties, or oil in pipelines that has not been delivered to the purchaser.
 
Derivatives
 
We use various financial instruments for non-trading purposes to manage and reduce price volatility and other market risks associated with our oil and natural gas production. These arrangements are structured to reduce our exposure to commodity price decreases, but they can also limit the benefit we might otherwise receive from commodity price increases. Our risk management activity is generally accomplished through over-the-counter derivative contracts with large financial institutions. We also use derivative instruments in the form of interest rate swaps, which hedge risk related to interest rate fluctuation.
 
We apply the provisions of ASC 815 (formerly SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”), which requires each derivative instrument to be recorded in the balance sheet at fair value. If a derivative has not been designated as a hedge or does not otherwise qualify for hedge accounting, it must be adjusted to fair value through earnings. However, if a derivative qualifies for hedge accounting, depending on the nature of the hedge, the effective portion of changes in fair value can be recognized in accumulated other comprehensive income or loss until such time as the hedged item is recognized in earnings. In order to qualify for cash flow hedge accounting, the cash flows from the hedging instrument must be highly effective in offsetting changes in cash flows of the hedged item. In addition, all hedging relationships must be designated, documented, and reassessed periodically.
 
We have elected to designate our outstanding interest rate swaps as cash flow hedges. The effective portion of the mark-to-market gain or loss on these derivative instruments is recorded in accumulated other comprehensive income or loss in partner’s equity and reclassified into earnings in the same period in which


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the hedged transaction affects earnings. Any ineffective portion of the mark-to-market gain or loss is recognized immediately in earnings. While management does not anticipate changing the designation of our interest rate swaps as hedges, factors beyond our control can preclude the use of hedge accounting.
 
We have not elected to designate our current portfolio of commodity derivative contracts as hedges. Therefore, changes in fair value of these derivative instruments are recognized in earnings each period.
 
Please read “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” for discussion regarding our sensitivity analysis for financial instruments.
 
New Accounting Pronouncements
 
FASB Launches Accounting Standards Codification
 
In June 2009, the FASB issued ASC 105-10 (formerly SFAS No. 168, “The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles”). ASC 105-10 establishes the FASB Accounting Standards Codification as the sole source of authoritative accounting principles recognized by the FASB to be applied by all nongovernmental entities in the preparation of financial statements in conformity with GAAP. ASC 105-10 was prospectively effective for financial statements issued for fiscal years ending on or after September 15, 2009, and interim periods within those fiscal years. The adoption of ASC 105-10 on July 1, 2009 did not impact our results of operations or financial condition.
 
Following the Codification, the FASB does not issue new standards in the form of Statements, FASB Staff Positions (“FSP”), or EITF Abstracts. Instead, it issues Accounting Standards Updates (“ASU”), which update the Codification, provide background information about the guidance, and provide the basis for conclusions on the changes to the Codification.
 
The Codification did not change GAAP; however, it did change the way GAAP is organized and presented. As a result, these changes impact how companies, including us, reference GAAP in their financial statements and in their significant accounting policies.
 
ASC 820-10 (formerly FSP No. FAS 157-2, “Effective Date of FASB Statement No. 157”)
 
In February 2008, the FASB issued ASC 820-10, which delayed the effective date of ASC 820-10 for one year for nonfinancial assets and liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). ASC 820-10 was prospectively effective for financial statements issued for fiscal years beginning after November 15, 2008, and interim periods within those fiscal years. We elected a partial deferral of ASC 820-10 for all instruments within the scope of ASC 820-10, including, but not limited to, our asset retirement obligations and indefinite lived assets. The adoption of ASC 820-10 on January 1, 2009 as it relates to nonfinancial assets and liabilities did not have a material impact on our results of operations or financial condition.
 
ASC 805 (formerly SFAS No. 141 (revised 2007), “Business Combinations”)
 
In December 2007, the FASB issued ASC 805, which establishes principles and requirements for the reporting entity in a business combination, including: (1) recognition and measurement in the financial statements of the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree; (2) recognition and measurement of goodwill acquired in the business combination or a gain from a bargain purchase; and (3) determination of the information to be disclosed to enable financial statement users to evaluate the nature and financial effects of the business combination. In April 2009, the FASB issued ASC 805-20 (formerly FSP No. FAS 141(R)-1, “Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arises from Contingencies”), which amends and clarifies ASC 805 to address application issues, including: (1) initial recognition and measurement; (2) subsequent measurement and accounting; and (3) disclosure of assets and liabilities arising from contingencies in a business combination. ASC 805 and ASC 805-20 were prospectively effective for business combinations consummated in fiscal years


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beginning on or after December 15, 2008. The accounting for transactions between entities under common control is unchanged under ASC 805 and ASC 805-20. The application of ASC 805 and ASC 805-20 to the acquisition of certain oil and natural gas properties and related assets in 2009 was nominal.
 
ASC 815-10 (formerly SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities — an amendment of FASB Statement No. 133”)
 
In March 2008, the FASB issued ASC 815-10, which requires enhanced disclosures: including (1) how and why an entity uses derivative instruments; (2) how derivative instruments and related hedged items are accounted for under ASC 815; and (3) how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. ASC 815-10 was prospectively effective for financial statements issued for fiscal years beginning on or after November 15, 2008, and interim periods within those fiscal years. The adoption of ASC 815-10 on January 1, 2009 required additional disclosures regarding our derivative instruments; however, it did not impact our results of operations or financial condition.
 
ASC 260-10 (formerly EITF Issue No. 07-4, “Application of the Two-Class Method under FASB Statement No. 128, Earnings per Share, to Master Limited Partnerships”)
 
In March 2008, the FASB issued ASC 260-10, which addresses how master limited partnerships should calculate earnings per unit using the two-class method and how current period earnings of a master limited partnership should be allocated to the general partner, limited partners, and other participating securities. ASC 260-10 was retrospectively effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those years. In this Report, periods prior to the adoption of ASC 260-10 have been restated to calculate earnings per unit in accordance with this pronouncement. The retrospective application of ASC 260-10 reduced our basic and diluted earnings per common unit by $0.01 for 2007. The adoption of ASC 260-10 did not have an impact on our basic or diluted earnings per common unit for 2008.
 
ASC 260-10 (formerly FSP No. EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities”)
 
In June 2008, the FASB issued ASC 260-10, which addresses whether instruments granted in unit-based payment transactions are participating securities prior to vesting and, therefore, need to be included in the earnings allocation for computing basic earnings per unit under the two-class method. ASC 260-10 was retroactively effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those years. The adoption of ASC 260-10 on January 1, 2009 did not have a material impact on our earnings per unit calculations. In this Report, periods prior to the adoption of ASC 260-10 have been restated to calculate earnings per unit in accordance with this pronouncement.
 
SEC Release No. 33-8995, “Modernization of Oil and Gas Reporting” (“Release 33-8995”)
 
In December 2008, the SEC issued Release 33-8995, which amends oil and natural gas reporting requirements under Regulations S-K and S-X. Release 33-8995 also adds a section to Regulation S-K (Subpart 1200) to codify the revised disclosure requirements in Securities Act Industry Guide 2, which is being phased out. Release 33-8995 permits the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes. Release 33-8995 will also allow companies to disclose their probable and possible reserves to investors at the company’s option. In addition, the new disclosure requirements require companies to: (1) report the independence and qualifications of its reserves preparer or auditor; (2) file reports when a third party is relied upon to prepare reserves estimates or conduct a reserves audit; and (3) report oil and gas reserves using an average price based upon the prior 12-month period rather than a year-end price, unless prices are defined by contractual arrangements, excluding escalations based on future conditions. Release 33-8995 was prospectively effective for financial statements issued for fiscal years ending on or after December 31, 2009.


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ASC 855-10 (formerly SFAS No. 165, “Subsequent Events”)
 
In June 2009, the FASB issued ASC 855-10 to establish general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or available to be issued. In particular, ASC 855-10 sets forth: (1) the period after the balance sheet date during which management of a reporting entity should evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements; (2) the circumstances under which an entity should recognize events or transactions occurring after the balance sheet date in its financial statements; and (3) the disclosures that an entity should make about events or transactions that occurred after the balance sheet date. ASC 855-10 was prospectively effective for financial statements issued for interim or annual periods ending after June 15, 2009. The adoption of ASC 855-10 on June 30, 2009 did not impact our results of operations or financial condition.
 
ASU No. 2009-05, “Fair Value Measurement and Disclosure: Measuring Liabilities at Fair Value” (“ASU 2009-05”)
 
In August 2009, the FASB issued ASU 2009-05 to provide clarification on measuring liabilities at fair value when a quoted price in an active market is not available. In particular, ASU 2009-05 specifies that a valuation technique should be applied that used either the quote of the liability when traded as an asset, the quoted prices for similar liabilities or similar liabilities when traded as assets, or another valuation technique consistent with existing fair value measurement guidance. ASU 2009-05 was prospectively effective for financial statements issued for interim or annual periods ending after October 1, 2009. The adoption of ASU 2009-05 on December 31, 2009 did not impact our results of operations or financial condition.
 
ASU No. 2010-03, “Oil and Gas Reserve Estimation and Disclosure” (“ASU 2010-03”)
 
In January 2010, the FASB issued ASU 2010-03 to align the oil and natural gas reserve estimation and disclosure requirements of Extractive Activities — Oil and Gas (ASC 932) with the requirements in the SEC’s final rule, “Modernization of the Oil and Gas Reporting.” ASU 2010-03 was prospectively effective for financial statements issued for annual periods ending on or after December 31, 2009.
 
ASU No. 2010-06, “Improving Disclosures about Fair Value Measurements” (“ASU 2010-06”)
 
In January 2010, the FASB issued ASU 2010-06 to require additional information to be disclosed principally in respect of level 3 fair value measurements and transfers to and from Level 1 and Level 2 measurements; in addition, enhanced disclosure is required concerning inputs and valuation techniques used to determine Level 2 and Level 3 fair value measurements. ASU 2010-06 was generally effective for interim and annual reporting periods beginning after December 15, 2009; however, the requirements to disclose separately purchases, sales, issuances, and settlements in the Level 3 reconciliation are effective for fiscal years beginning after December 15, 2010 (and for interim periods within such years) with early adoption allowed. The adoption of ASU 2010-06 on December 31, 2009 did not impact our results of operations or financial condition.
 
Information Concerning Forward-Looking Statements
 
This Report contains forward-looking statements, which give our current expectations or forecasts of future events. Forward-looking statements can be identified by the fact that they do not relate strictly to historical or current facts. These statements may include words such as “may,” “will,” “could,” “anticipate,” “estimate,” “expect,” “project,” “intend,” “plan,” “believe,” “should,” “predict,” “potential,” “pursue,” “target,” “continue,” and other words and terms of similar meaning. In particular, forward-looking statements included in this Report relate to, among other things, the following:
 
  •  the occurrence of any event, change, or other circumstance that could affect the consummation of the Merger or give rise to the termination of the Merger Agreement in connection with the Merger;


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  •  the inability to complete the Merger due to the failure to satisfy any conditions required to consummate the Merger;
 
  •  items of income and expense (including, without limitation, LOE, production taxes, DD&A, and G&A);
 
  •  expected capital expenditures and the focus of our capital program;
 
  •  areas of future growth;
 
  •  our development and exploitation programs;
 
  •  future secondary development and tertiary recovery potential;
 
  •  anticipated prices for oil and natural gas and expectations regarding differentials between wellhead prices and benchmark prices (including, without limitation, the effects of the worldwide economic recession);
 
  •  projected results of operations;
 
  •  timing and amount of future production of oil and natural gas;
 
  •  availability of pipeline capacity;
 
  •  expected commodity derivative positions and payments related thereto (including the ability of counterparties to fulfill obligations);
 
  •  expectations regarding working capital, cash flow, and liquidity;
 
  •  projected borrowings under our revolving credit facility (and the ability of lenders to fund their commitments); and
 
  •  the marketing of our oil and natural gas production.
 
You are cautioned not to place undue reliance on such forward-looking statements, which speak only as of the date of this Report. Our actual results may differ significantly from the results discussed in the forward-looking statements. Such statements involve risks and uncertainties, including, but not limited to, the matters discussed in “Item 1A. Risk Factors” and elsewhere in this Report and in our other filings with the SEC. If one or more of these risks or uncertainties materialize (or the consequences of such a development changes), or should underlying assumptions prove incorrect, actual outcomes may vary materially from those forecasted or expected. We undertake no responsibility to update forward-looking statements for changes related to these or any other factors that may occur subsequent to this filing for any reason.
 
Except for our obligations to disclose material information under United States federal securities laws, we undertake no obligation to release publicly any revision to any forward-looking statement, to report events or circumstances after the date of this Report, or to report the occurrence of unanticipated events.
 
ITEM 7A.   QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
 
The primary objective of the following information is to provide quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil and natural gas prices and interest rates. The disclosures are not meant to be precise indicators of exposure, but rather indicators of potential exposure. This information provides indicators of how we view and manage our ongoing market risk exposures. We do not enter into market risk sensitive instruments for speculative trading purposes.
 
Derivative policy.  Due to the volatility of crude oil and natural gas prices, we enter into various derivative instruments to manage and reduce our exposure to changes in the market price of crude oil and natural gas. We use options (including floors and collars) and fixed price swaps to mitigate the impact of downward swings in prices on our cash available for distribution. All contracts are settled with cash and do


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not require the delivery of physical volumes to satisfy settlement. While this strategy may result in us having lower net cash inflows in times of higher oil and natural gas prices than we would otherwise have, had we not utilized these instruments, management believes that the resulting reduced volatility of cash flow is beneficial.
 
Counterparties.  At December 31, 2009, we had committed 10 percent of greater (in terms of fair market value) of either our oil or natural gas commodity derivative contracts in asset positions to the following counterparties:
 
                 
    Fair Market Value of
  Fair Market Value of
    Oil Derivative
  Natural Gas Derivative
    Contracts
  Contracts
Counterparty
  Committed   Committed
    (In thousands)
 
BNP Paribas
  $ 13,955     $ 2,795  
Calyon
    3,820       6,167  
Royal Bank of Canada
    4,158       (a )
Wachovia
    3,069       1,148  
 
 
(a) Less than 10 percent.
 
In order to mitigate the credit risk of financial instruments, we enter into master netting agreements with certain counterparties. The master netting agreement is a standardized, bilateral contract between a given counterparty and us. Instead of treating separately each derivative financial transaction between our counterparty and us, the master netting agreement enables our counterparty and us to aggregate all financial trades and treat them as a single agreement. This arrangement is intended to benefit us in three ways: (1) the netting of the value of all trades reduces likelihood of our counterparties requiring daily collateral posting by us; (2) default by a counterparty under one financial trade can trigger rights to terminate all financial trades with such counterparty; and (3) netting of settlement amounts reduces our credit exposure to a given counterparty in the event of close-out.
 
Commodity price sensitivity.  We manage commodity price risk with swap contracts, put contracts, collars, and floor spreads. Swap contracts provide a fixed price for a notional amount of sales volumes. Put contracts provide a fixed floor price on a notional amount of sales volumes while allowing full price participation if the relevant index price closes above the floor price. Collars provide a floor price on a notional amount of sales volumes while allowing some additional price participation if the relevant index price closes above the floor price.
 
From time to time, we enter into floor spreads.  In a floor spread, we purchase puts at a specified price (a “purchased put”) and also sell a put at a lower price (a “short put”). This strategy enables us to achieve some downside protection for a portion of our production, while funding the cost of such protection by selling a put at a lower price. If the price of the commodity falls below the strike price of the purchased put, then we have protection against additional commodity price decreases for the covered production down to the strike price of the short put. At commodity prices below the strike price of the short put, the benefit from the purchased put is generally offset by the expense associated with the short put. For example, in 2007, we purchased oil put options for 2,000 Bbls/D in 2010 at $65 per Bbl. As NYMEX prices increased in 2008, we wanted to protect downside price exposure at the higher price. In order to do this, we purchased oil put options for 2,000 Bbls/D in 2010 at $75 per Bbl and simultaneously sold oil put options for 2,000 Bbls/D in 2010 at $65 per Bbl. Thus, after these transactions were completed, we had purchased two oil put options for 2,000 Bbls/D in 2010 (one at $65 per Bbl and one at $75 per Bbl) and sold one oil put option for 2,000 Bbls/D in 2010 at $65 per Bbl. However, the net effect resulted in us owning one oil put option for 2,000 Bbls/D at


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$75 per Bbl. In the following tables, the purchased floor component of these floor spreads are shown net and included with our other floor contracts.
 
The counterparties to our commodity derivative contracts are a diverse group of five institutions, all of which are currently rated A or better by Standard & Poor’s and/or Fitch. As of December 31, 2009, the fair market value of our oil derivative contracts was a net liability of approximately $3.9 million and the fair market value of our natural gas derivative contracts was a net asset of approximately $10.6 million. Based on our open commodity derivative positions at December 31, 2009, a 10 percent increase in the respective NYMEX prices for oil and natural gas would decrease our net commodity derivative asset by approximately $28.8 million, while a 10 percent decrease in the respective NYMEX prices for oil and natural gas would increase our net commodity derivative asset by approximately $30.2 million.
 
The following tables summarize our open commodity derivative contracts as of December 31, 2009:
 
Oil Derivative Contracts
 
                                                         
    Average
    Weighted
    Average
    Weighted
    Average
    Weighted
       
    Daily
    Average
    Daily
    Average
    Daily
    Average
    Asset (Liability)
 
    Floor
    Floor
    Cap
    Cap
    Swap
    Swap
    Fair Market
 
Period
  Volume     Price     Volume     Price     Volume     Price     Value  
    (Bbl)     (per Bbl)     (Bbl)     (per Bbl)     (Bbl)     (per Bbl)     (In thousands)  
2010
                                                  $ (1,476 )
      880     $ 80.00       440     $ 93.80       760     $ 75.43          
      2,000       75.00       1,000       77.23       250       65.95          
      760       67.00                                  
2011
                                                    2,638  
      1,880       80.00       1,440       95.41       760       78.46          
      1,000       70.00                                  
      760       65.00                   250       69.65          
2012
                                                    (5,020 )
      750       70.00       500       82.05       210       81.62          
      1,510       65.00       250       79.25       1,300       76.54          
                                                         
                                                    $ (3,858 )
                                                         


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Natural Gas Derivative Contracts
 
                                                         
    Average
    Weighted
    Average
    Weighted
    Average
    Weighted
       
    Daily
    Average
    Daily
    Average
    Daily
    Average
    Asset
 
    Floor
    Floor
    Cap
    Cap
    Swap
    Swap
    Fair Market
 
Period
  Volume     Price     Volume     Price     Volume     Price     Value  
    (Mcf)     (per Mcf)     (Mcf)     (per Mcf)     (Mcf)     (per Mcf)     (In thousands)  
2010
                                                  $ 7,963  
      3,800     $ 8.20       3,800     $ 9.58       5,452     $ 6.20          
      4,698       7.26                   550       5.86          
2011
                                                    2,105  
      3,398       6.31                   7,952       6.36          
                              550       5.86          
2012
                                                    547  
      898       6.76                   5,452       6.26          
                              550       5.86          
                                                         
                                                    $ 10,615  
                                                         
 
Interest rate sensitivity.  At December 31, 2009, we had outstanding borrowings under our revolving credit facility of $255 million, which is subject to floating market rates of interest that are linked to the Eurodollar rate. At this level of floating rate debt, if the Eurodollar rate increased 10 percent, we would incur an additional $1.0 million of interest expense per year, and if the Eurodollar rate decreased 10 percent, we would incur $1.0 million less.
 
We manage interest rate risk with interest rate swaps whereby we swap floating rate debt under the OLLC Credit Agreement with a weighted average fixed rate. As of December 31, 2009, the fair market value of our interest rate swaps was a net liability of approximately $3.7 million. If the Eurodollar rate increased 10 percent, the fair value would decrease to approximately $3.4 million, and if the Eurodollar rate decreased 10 percent, the fair value would increase to approximately $3.9 million.
 
The following table summarizes our open interest rate swaps as of December 31, 2009:
 
                         
    Notional
  Fixed
  Floating
Term
  Amount   Rate   Rate
    (In thousands)        
 
Jan. 2010 — Jan. 2011
  $ 50,000       3.1610 %     1-month LIBOR  
Jan. 2010 — Jan. 2011
    25,000       2.9650 %     1-month LIBOR  
Jan. 2010 — Jan. 2011
    25,000       2.9613 %     1-month LIBOR  
Jan. 2010 — Mar. 2012
    50,000       2.4200 %     1-month LIBOR  


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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
To the Board of Directors of Encore Energy Partners GP LLC
and Unitholders of Encore Energy Partners LP:
 
We have audited the accompanying consolidated balance sheets of Encore Energy Partners LP (the “Partnership”) as of December 31, 2009 and 2008, and the related consolidated statements of operations, partners’ equity and comprehensive income (loss), and cash flows for each of the three years in the period ended December 31, 2009. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
 
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
 
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Encore Energy Partners LP at December 31, 2009 and 2008, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2009, in conformity with U.S. generally accepted accounting principles.
 
As discussed in Note 2 to the consolidated financial statements, effective January 1, 2009, the Partnership retroactively changed its method of calculating basic and diluted earnings per common unit with the adoption of the guidance originally issued in EITF Issue No. 07-4, Application of the Two-Class Method under FASB Statement No. 128, Earnings per Share, to Master Limited Partnerships (codified in FASB ASC Topic 260, Earnings per Share) and FSP No. EITF 03-6-1, Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities (codified in FASB ASC Topic 260, Earnings Per Share). Additionally, as discussed in Note 2 to the consolidated financial statements, the Partnership has changed its reserve estimates and related disclosures as a result of adopting new oil and gas reserve estimation and disclosure requirements resulting from Accounting Standards Update No. 2010-03, Oil and Gas Reserve Estimation and Disclosures, effective for annual reporting periods ended on or after December 31, 2009.
 
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Encore Energy Partners LP’s internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 24, 2010 expressed an unqualified opinion thereon.
 
/s/  Ernst & Young LLP
Fort Worth, Texas
February 24, 2010


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ENCORE ENERGY PARTNERS LP

CONSOLIDATED BALANCE SHEETS
 
                 
    December 31,  
    2009     2008  
    (In thousands, except unit amounts)  
 
ASSETS
Current assets:
               
Cash and cash equivalents
  $ 1,754     $ 619  
Accounts receivable:
               
Trade
    24,543       18,965  
Affiliate
    8,213       3,896  
Derivatives
    12,881       75,131  
Other
    857       831  
                 
Total current assets
    48,248       99,442  
                 
Properties and equipment, at cost — successful efforts method:
               
Proved properties, including wells and related equipment
    851,833       814,903  
Unproved properties
    55       84  
Accumulated depletion, depreciation, and amortization
    (210,417 )     (154,584 )
                 
      641,471       660,403  
                 
Other property and equipment
    863       802  
Accumulated depreciation
    (419 )     (240 )
                 
      444       562  
                 
Goodwill
    9,290       9,290  
Other intangibles, net
    3,316       3,662  
Derivatives
    13,423       38,497  
Other
    3,459       1,457  
                 
Total assets
  $ 719,651     $ 813,313  
                 
 
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
               
Accounts payable:
               
Trade
  $ 577     $ 1,036  
Affiliate
    2,780       5,468  
Accrued liabilities:
               
Lease operating
    3,683       4,252  
Development capital
    1,484       2,277  
Interest
    429       126  
Production, ad valorem, and severance taxes
    10,665       10,634  
Derivatives
    9,815       1,297  
Oil and natural gas revenues payable
    1,598       1,287  
Other
    1,659       1,502  
                 
Total current liabilities
    32,690       27,879  
Derivatives
    13,401       3,491  
Future abandonment cost, net of current portion
    12,556       11,987  
Long-term debt
    255,000       150,000  
Other
          605  
                 
Total liabilities
    313,647       193,962  
                 
Commitments and contingencies (see Note 4)
               
Partners’ equity:
               
Limited partners — 45,285,347 and 33,077,610 common units issued and outstanding, respectively
    409,777       616,076  
General partner — 504,851 general partner units issued and outstanding
    (353 )     7,534  
Accumulated other comprehensive loss
    (3,420 )     (4,259 )
                 
Total partners’ equity
    406,004       619,351  
                 
Total liabilities and partners’ equity
  $ 719,651     $ 813,313  
                 
 
The accompanying notes are an integral part of these consolidated financial statements.


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ENCORE ENERGY PARTNERS LP

CONSOLIDATED STATEMENTS OF OPERATIONS
 
                         
    Year Ended December 31,  
    2009     2008     2007  
    (In thousands, except per unit amounts)  
 
Revenues:
                       
Oil
  $ 127,611     $ 226,613     $ 135,546  
Natural gas
    22,428       53,944       39,119  
Marketing
    478       5,324       8,582  
                         
Total revenues
    150,517       285,881       183,247  
                         
Expenses:
                       
Production:
                       
Lease operating
    41,676       44,752       33,980  
Production, ad valorem, and severance taxes
    16,099       28,147       17,712  
Depletion, depreciation, and amortization
    56,757       57,537       47,494  
Exploration
    3,132       196       126  
General and administrative
    11,375       16,605       15,245  
Marketing
    302       5,466       6,673  
Derivative fair value loss (gain)
    47,464       (96,880 )     26,301  
Other operating
    3,099       1,670       1,426  
                         
Total expenses
    179,904       57,493       148,957  
                         
Operating income (loss)
    (29,387 )     228,388       34,290  
                         
Other income (expenses):
                       
Interest
    (10,974 )     (6,969 )     (12,702 )
Other
    46       99       196  
                         
Total other expenses
    (10,928 )     (6,870 )     (12,506 )
                         
Income (loss) before income taxes
    (40,315 )     221,518       21,784  
Income tax provision
    (14 )     (762 )     (78 )
                         
Net income (loss)
  $ (40,329 )   $ 220,756     $ 21,706  
                         
Net income (loss) allocation (see Note 8):
                       
Limited partners’ interest in net income (loss)
  $ (39,913 )   $ 163,070     $ (18,877 )
                         
General partner’s interest in net income (loss)
  $ (592 )   $ 2,648     $ (394 )
                         
Net income (loss) per common unit:
                       
Basic
  $ (1.01 )   $ 5.33     $ (0.79 )
Diluted
  $ (1.01 )   $ 5.21     $ (0.79 )
Weighted average common units outstanding:
                       
Basic
    39,366       30,568       23,877  
Diluted
    39,366       31,938       23,877  
 
The accompanying notes are an integral part of these consolidated financial statements.


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ENCORE ENERGY PARTNERS LP

CONSOLIDATED STATEMENTS OF PARTNERS’ EQUITY AND
COMPREHENSIVE INCOME (LOSS)
 
                                                         
                                  Accumulated
       
    Owner’s
    Limited
                Other
    Total
 
    Net
    Partners     General Partner     Comprehensive
    Partners’
 
    Equity     Units     Amount     Units     Amount     Loss     Equity  
    (In thousands, except per unit amounts)  
 
Balance at December 31, 2006
  $ 197,810           $           $     $     $ 197,810  
Contribution by EAC in connection with acquisition of the Elk Basin Assets
    103,062       10,280             221                   103,062  
Net contributions from owner
    119,867                                     119,867  
Equity adjustment due to combination of entities under common control
    (1,306 )                                   (1,306 )
Contribution of Permian Basin Assets by EAC
    (26,229 )     4,043       26,229                          
Allocation of owner’s net equity — Permian Basin Assets
    (91,956 )           90,118             1,838              
Allocation of owner’s net equity — Permian and Williston Basin Assets
    (96,877 )           94,595             2,282              
Allocation of owner’s net equity — Arkoma Basin Assets
    (17,282 )           16,874             408              
Allocation of owner’s net equity — Williston Basin Assets
    (35,034 )           34,209             825              
Allocation of owner’s net equity — Rockies and Permian Basin Assets
    (192,737 )           188,197             4,540              
Proceeds from issuance of common units, net of offering costs
          9,864       193,863       284       (402 )           193,461  
Non-cash unit-based compensation
                6,665             139             6,804  
Cash distributions to unitholders ($0.053 per unit)
                (1,311 )           (27 )           (1,338 )
Net income attributable to owner related to pre-partnership and pre-IPO operations
    40,682                                     40,682  
Net loss attributable to unitholders
                (18,587 )           (389 )           (18,976 )
                                                         
Balance at December 31, 2007
          24,187       630,852       505       9,214             640,066  
Net distributions to owner
                (47,629 )           (1,166 )     (1 )     (48,796 )
Deemed distributions to affiliates in connection with acquisition of the Permian and Williston Basin Assets
          6,885       (122,083 )           (2,944 )           (125,027 )
Issuance of common units in exchange for net profits interest in certain Crockett County properties
          284       5,748                         5,748  
Non-cash unit-based compensation
                5,180             83             5,263  
Cash distributions to unitholders ($2.3111 per unit)
                (73,234 )           (1,167 )           (74,401 )
Vesting of phantom units
          7                                
Conversion of management incentive units
          1,715                                
Components of comprehensive income:
                                                       
Net income attributable to owner related to pre-partnership operations of the Permian and Williston Basin Assets
                3,321             80             3,401  
Net income attributable to owner related to pre-partnership operations of the Arkoma Basin Assets
                5,922             143             6,065  
Net income attributable to owner related to pre-partnership operations of the Williston Basin Assets
                6,637             164             6,801  
Net income attributable to owner related to pre-partnership operations of the Rockies and Permian Basin Assets
                34,540             833             35,373  
Net income attributable to unitholders
                166,822             2,294             169,116  
Change in deferred hedge loss on interest rate swaps, net of tax of $12
                                  (4,258 )     (4,258 )
                                                         
Total comprehensive income
                                                    216,498  
                                                         
Balance at December 31, 2008
          33,078       616,076       505       7,534       (4,259 )     619,351  
Net distributions to owner
                (11,137 )           (272 )           (11,409 )
Deemed distributions in connection with acquisition of the Arkoma Basin Assets
                (45,333 )           (1,088 )           (46,421 )
Deemed distributions in connection with acquisition of the Williston Basin Assets
                (24,593 )           (593 )           (25,186 )
Deemed distributions in connection with acquisition of the Rockies and Permian Basin Assets
                (175,408 )           (4,232 )           (179,640 )
Proceeds from issuance of common units, net of offering costs
          12,190       170,000             (114 )           169,886  
Non-cash unit-based compensation
                560             5             565  
Cash distributions to unitholders ($2.05 per unit)
                (80,617 )           (1,035 )           (81,652 )
Vesting of phantom units and conversion of management incentive units
          17                                
Components of comprehensive loss:
                                                       
Net loss attributable to owners prior to acquisition of the Williston Basin Assets
                (188 )           (5 )           (193 )
Net income attributable to owners prior to acquisition of the Rockies and Permian Basin Assets
                360             9             369  
Net loss attributable to unitholders
                (39,943 )           (562 )           (40,505 )
Change in deferred hedge loss on interest rate swaps, net of tax of $2
                                  839       839  
                                                         
Total comprehensive loss
                                                    (39,490 )
                                                         
Balance at December 31, 2009
  $       45,285     $ 409,777       505     $ (353 )   $ (3,420 )   $ 406,004  
                                                         
 
The accompanying notes are an integral part of these consolidated financial statements.


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ENCORE ENERGY PARTNERS LP
 
CONSOLIDATED STATEMENTS OF CASH FLOWS
 
                         
    Year Ended December 31,  
    2009     2008     2007  
    (In thousands)  
 
Cash flows from operating activities:
                       
Net income (loss)
  $ (40,329 )   $ 220,756     $ 21,706  
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
                       
Depletion, depreciation, and amortization
    56,757       57,537       47,494  
Non-cash exploration expense
          13       23  
Deferred taxes
    (286 )     322       16  
Non-cash unit-based compensation expense
    565       5,232       6,804  
Non-cash derivative loss (gain)
    117,685       (92,286 )     27,543  
Other
    5,207       1,012       695  
Changes in operating assets and liabilities, net of effects from acquisitions:
                       
Accounts receivable
    (10,591 )     12,437       (20,203 )
Current derivatives
    (2,020 )     (9,586 )     (2,700 )
Other current assets
    (221 )     (176 )     (417 )
Long-term derivatives
    (9,072 )     (6,881 )     (19,717 )
Other assets
    (3 )     578       (812 )
Accounts payable
    (2,555 )     (1,748 )     3,268  
Other current liabilities
    (167 )     2,025       9,669  
                         
Net cash provided by operating activities
    114,970       189,235       73,369  
                         
Cash flows from investing activities:
                       
Purchases of other property and equipment
    (88 )     (315 )     (510 )
Acquisition of oil and natural gas properties
    (31,960 )     (215 )     (495,252 )
Development of oil and natural gas properties
    (9,037 )     (41,803 )     (29,010 )
                         
Net cash used in investing activities
    (41,085 )     (42,333 )     (524,772 )
                         
Cash flows from financing activities:
                       
Proceeds from issuance of common units, net of issuance costs
    170,089             193,461  
Proceeds from long-term debt, net of issuance costs
    227,061       243,310       270,758  
Payments on long-term debt
    (125,000 )     (141,000 )     (225,000 )
Deemed distributions to affiliates in connection with acquisitions
    (251,247 )     (125,027 )      
Cash distributions to unitholders
    (81,652 )     (74,401 )     (1,338 )
Contribution by EAC in connection with purchase of Elk Basin Assets
                93,658  
Net contributions from (distributions to) owner related to pre-partnership or pre-IPO operations
    (11,409 )     (48,796 )     119,867  
Other
    (592 )     (372 )      
                         
Net cash provided by (used in) financing activities
    (72,750 )     (146,286 )     451,406  
                         
Increase in cash and cash equivalents
    1,135       616       3  
Cash and cash equivalents, beginning of period
    619       3        
                         
Cash and cash equivalents, end of period
  $ 1,754     $ 619     $ 3  
                         
 
The accompanying notes are an integral part of these consolidated financial statements


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ENCORE ENERGY PARTNERS LP
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 
Note 1.   Formation of the Partnership and Description of Business
 
Encore Energy Partners LP (together with its subsidiaries, “ENP”), a Delaware limited partnership, was formed by Encore Acquisition Company (together with its subsidiaries, “EAC”), a publicly traded Delaware corporation, to acquire, exploit, and develop oil and natural gas properties and to acquire, own, and operate related assets. Encore Energy Partners GP LLC (the “General Partner”), a Delaware limited liability company and indirect wholly owned subsidiary of EAC, serves as ENP’s general partner and Encore Energy Partners Operating LLC (“OLLC”), a Delaware limited liability company and direct wholly owned subsidiary of ENP, owns and operates ENP’s properties. ENP’s 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.
 
EAC’s Merger with Denbury
 
On October 31, 2009, EAC, the ultimate parent of the General Partner, entered into an Agreement and Plan of Merger (the “Merger Agreement”) with Denbury Resources Inc. (“Denbury”) pursuant to which EAC has agreed to merge with and into Denbury, with Denbury as the surviving entity (the “Merger”). The Merger Agreement, which was unanimously approved by EAC’s Board of Directors and by Denbury’s Board of Directors, provides for Denbury’s acquisition of all of the issued and outstanding shares of EAC common stock. Completion of the Merger is conditioned upon, among other things, approval by the stockholders of both EAC and Denbury.
 
Initial Public Offering and Concurrent Transactions
 
In September 2007, ENP completed its initial public offering (“IPO”) of 9,000,000 common units at a price to the public of $21.00 per unit. In October 2007, the underwriters exercised in full their over-allotment option to purchase an additional 1,148,400 common units. The net proceeds of approximately $193.5 million, after deducting the underwriters’ discount and a structuring fee of approximately $14.9 million, in the aggregate, and offering expenses of approximately $4.7 million, were used to repay in full $126.4 million of outstanding indebtedness under a subordinated credit agreement with EAP Operating, LLC (“EAP Operating”), a Delaware limited liability company and direct wholly owned subsidiary of EAC, and reduce outstanding borrowings under OLLC’s revolving credit facility. Please read “Note 6. Long-Term Debt” for additional discussion of ENP’s long-term debt.
 
At the closing of the IPO, the following transactions, among others, were completed:
 
(a) ENP entered into a contribution, conveyance and assumption agreement (the “Contribution Agreement”) with the General Partner, OLLC, EAC, Encore Operating, L.P. (“Encore Operating”), a Texas limited partnership and indirect wholly owned subsidiary of EAC, and Encore Partners LP Holdings LLC, a Delaware limited liability company and direct wholly owned subsidiary of EAC. The following transactions, among others, occurred pursuant to the Contribution Agreement:
 
  •  Encore Operating contributed certain oil and natural gas properties and related assets in the Permian Basin in West Texas (the “Permian Basin Assets”) to ENP in exchange for 4,043,478 common units; and


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ENCORE ENERGY PARTNERS LP
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
 
  •  EAC agreed to indemnify ENP for certain environmental liabilities, tax liabilities, and title defects, as well as defects relating to retained assets and liabilities, occurring or existing before the closing.
 
These transfers and distributions were made in a series of steps outlined in the Contribution Agreement. In connection with the issuance of the common units by ENP in exchange for the Permian Basin Assets, the IPO, and the exercise of the underwriters’ over-allotment option to purchase additional common units, the General Partner exchanged such number of common units for general partner units as was necessary to enable it to maintain its then two percent general partner interest in ENP. The General Partner received the common units through capital contributions from EAC of common units it owned.
 
(b) ENP entered into an administrative services agreement (the “Administrative Services Agreement”) with the General Partner, OLLC, Encore Operating, and EAC pursuant to which Encore Operating performs administrative services for ENP. Please read “Note 11. Related Party Transactions” for additional discussion regarding the Administrative Services Agreement.
 
(c) The Encore Energy Partners GP LLC Long-Term Incentive Plan (the “LTIP”) was adopted by the board of directors of the General Partner. Please read “Note 9. Unit-Based Compensation Plans” for additional discussion regarding the LTIP.
 
Note 2.   Summary of Significant Accounting Policies
 
Principles of Consolidation
 
ENP’s consolidated financial statements include the accounts of its wholly owned subsidiaries. All material intercompany balances and transactions have been eliminated in consolidation.
 
As discussed in “Note 1. Formation of the Partnership and Description of Business,” upon completion of ENP’s IPO, EAC contributed the Permian Basin Assets to ENP. The Permian Basin Assets are considered the predecessor to ENP (the “Predecessor”), and therefore, the historical results of operations of ENP include the results of operations of the Permian Basin Assets for all periods presented.
 
In February 2008, ENP acquired certain oil and natural gas properties and related assets in the Permian Basin in West Texas and in the Williston Basin in North Dakota (the “Permian and Williston Basin Assets”) from Encore Operating. In January 2009, ENP acquired certain oil and natural gas properties and related assets in the Arkoma Basin in Arkansas and royalty interest properties primarily in Oklahoma, as well as 10,300 unleased mineral acres (the “Arkoma Basin Assets”) from Encore Operating. In June 2009, ENP acquired certain oil and natural gas properties and related assets in the Williston Basin in North Dakota and Montana (the “Williston Basin Assets”) from Encore Operating. In August 2009, ENP acquired certain oil and natural gas properties and related assets in the Big Horn Basin in Wyoming, the Permian Basin in West Texas and New Mexico, and the Williston Basin in Montana and North Dakota (the “Rockies and Permian Basin Assets”) from Encore Operating. Because these assets were acquired from an affiliate, the acquisitions were accounted for as transactions between entities under common control, similar to a pooling of interests, whereby the assets and liabilities of the acquired properties were recorded at Encore Operating’s carrying value and ENP’s historical financial information was recast to include the acquired properties for all periods in which the properties were owned by Encore Operating. Accordingly, the consolidated financial statements and notes thereto reflect the historical results of ENP combined with those of the Permian and Williston Basin Assets, the Arkoma Basin Assets, the Williston Basin Assets, and the Rockies and Permian Basin Assets. Please read “Note 3. Acquisitions” for additional discussion of these acquisitions.
 
The results of operations of the Williston Basin Assets and the Rockies and Permian Basin Assets related to pre-partnership operations were allocated to the EAC affiliates based on their respective ownership percentages in ENP. The effect of recasting ENP’s consolidated financial statements to account for this


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ENCORE ENERGY PARTNERS LP
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
common control transaction increased ENP’s net income by approximately $42.2 million and $23.9 million in 2008 and 2007, respectively.
 
ENP, the Permian Basin Assets, the Permian and Williston Basin Assets, the Arkoma Basin Assets, Williston Basin Assets, and the Rockies and Permian Basin Assets were owned by EAC prior to the closing of the IPO, with the exception of management incentive units owned by certain executive officers of the General Partner.
 
Use of Estimates
 
Preparing financial statements in conformity with accounting principles generally accepted in the United States (“GAAP”) requires management to make certain estimations and assumptions that affect the reported amounts of assets, liabilities, revenues, and expenses, and the disclosure of contingent assets and liabilities in the consolidated financial statements. Actual results could differ materially from those estimates.
 
Estimates made in preparing these consolidated financial statements include, among other things, estimates of the proved oil and natural gas reserve volumes used in calculating depletion, depreciation, and amortization (“DD&A”) expense; the estimated future cash flows and fair value of properties used in determining the need for any impairment write-down; operating costs accrued; volumes and prices for revenues accrued; estimates of the fair value of unit-based compensation awards; and the timing and amount of future abandonment costs used in calculating asset retirement obligations. Changes in the assumptions used could have a significant impact on reported results in future periods.
 
Cash and Cash Equivalents
 
Cash and cash equivalents include cash in banks, money market accounts, and all highly liquid investments with an original maturity of three months or less. On a bank-by-bank basis and considering legal right of offset, cash accounts that are overdrawn are reclassified to current liabilities and any change in cash overdrafts is shown as “Change in cash overdrafts” in the “Financing activities” section of ENP’s Consolidated Statements of Cash Flows.
 
Prior to the formation of ENP, EAC provided cash as needed to support the operations of the Predecessor and collected cash from sales of production. Net cash received by or paid to EAC for periods prior to the properties’ ownership by ENP is reflected as net contributions from owner or net distributions to owner on the accompanying Consolidated Statements of Partners’ Equity and Comprehensive Income (Loss) and Consolidated Statements of Cash Flows.
 
The following table sets forth supplemental disclosures of cash flow information for the periods indicated:
 
                         
    Year Ended December 31,
    2009   2008   2007
    (In thousands)
 
Cash paid during the period for:
                       
Interest
  $ 9,761     $ 6,614     $ 11,857  
Income taxes
    297              
Non-cash investing and financing activities:
                       
Contribution of commodity derivative contracts from EAC
                9,404  
Contribution of Permian Basin Assets from EAC
                26,229  
Issuance of common units in connection with acquisition of net profits interest in certain Crockett County properties(a)
          5,748        
Issuance of common units in connection with acquisition of the Permian and Williston Basin Assets(a)
          125,027        
 
 
(a) Please read “Note 3. Acquisitions” for additional discussion.


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
 
Accounts Receivable
 
Trade accounts receivable, which are primarily from oil and natural gas sales, are recorded at the invoiced amount and do not bear interest. ENP routinely reviews outstanding accounts receivable balances and assesses the financial strength of its customers and records a reserve for amounts not expected to be fully recovered. Actual balances are not applied against the reserve until substantially all collection efforts have been exhausted. At December 31, 2009 and 2008, ENP had no allowance for doubtful accounts.
 
Properties and Equipment
 
Oil and Natural Gas Properties.  ENP uses the successful efforts method of accounting for its oil and natural gas properties under Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 932 (formerly Statement of Financial Accounting Standards (“SFAS”) No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies”). Under this method, all costs associated with productive and nonproductive development wells are capitalized. Exploration expenses, including geological and geophysical expenses and delay rentals, are charged to expense as incurred. Costs associated with drilling exploratory wells are initially capitalized pending determination of whether the well is economically productive or nonproductive.
 
If an exploratory well does not find reserves or does not find reserves in a sufficient quantity as to make them economically producible, the previously capitalized costs would be expensed in ENP’s Consolidated Statements of Operations and shown as an adjustment to net income (loss) in the “Operating activities” section of ENP’s Consolidated Statements of Cash Flows in the period in which the determination was made. If an exploratory well finds reserves but they cannot be classified as proved, ENP continues to capitalize the associated cost as long as the well has found a sufficient quantity of reserves to justify its completion as a producing well and ENP is making sufficient progress in assessing the reserves and the operating viability of the project. If subsequently it is determined that these conditions do not continue to exist, all previously capitalized costs associated with the exploratory well would be expensed and shown as an adjustment to net income (loss) in the “Operating activities” section of ENP’s Consolidated Statements of Cash Flows in the period in which the determination was made. Re-drilling or directional drilling in a previously abandoned well is classified as development or exploratory based on whether it is in a proved or unproved reservoir. Costs for repairs and maintenance to sustain or increase production from the existing producing reservoir are charged to expense as incurred. Costs to recomplete a well in a different unproved reservoir are capitalized pending determination that economic reserves have been added. If the recompletion is unsuccessful, the costs would be charged to expense. All capitalized costs associated with both development and exploratory wells are shown as “Development of oil and natural gas properties” in the “Investing activities” section of ENP’s Consolidated Statements of Cash Flows.
 
Significant tangible equipment added or replaced that extends the useful or productive life of the property is capitalized. Costs to construct facilities or increase the productive capacity from existing reservoirs are capitalized. Capitalized costs are amortized on a unit-of-production basis over the remaining life of proved developed reserves or total proved reserves, as applicable. Natural gas volumes are converted to barrels of oil equivalent (“BOE”) at the rate of six thousand cubic feet (“Mcf”) of natural gas to one barrel (“Bbl”) of oil.
 
The costs of retired, sold, or abandoned properties that constitute part of an amortization base are charged or credited, net of proceeds received, to accumulated DD&A.
 
Miller and Lents, Ltd., ENP’s independent reserve engineer, estimates ENP’s reserves annually on December 31. This results in a new DD&A rate which ENP uses for the preceding fourth quarter after adjusting for fourth quarter production. ENP internally estimates reserve additions and reclassifications of reserves from proved undeveloped to proved developed at the end of the first, second, and third quarters for use in determining a DD&A rate for the respective quarter.


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
In accordance with ASC 360-10, 205, 840, 958, and 855-10-60-1 (formerly SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets”) ENP assesses the need for an impairment of long-lived assets to be held and used, including proved oil and natural gas properties, whenever events and circumstances indicate that the carrying value of the asset may not be recoverable. If impairment is indicated based on a comparison of the asset’s carrying value to its undiscounted expected future net cash flows, then an impairment charge is recognized to the extent the asset’s carrying value exceeds its fair value. Expected future net cash flows are based on existing proved reserves (and appropriately risk-adjusted probable reserves), forecasted production information, and management’s outlook of future commodity prices. Any impairment charge incurred is expensed and reduces the net basis in the asset. Management aggregates proved property for impairment testing the same way as for calculating DD&A. The price assumptions used to calculate undiscounted cash flows is based on judgment. ENP uses prices consistent with the prices it believes a market participant would use in bidding on acquisitions and/or assessing capital projects. These price assumptions are critical to the impairment analysis as lower prices could trigger impairment.
 
Unproved properties, the majority of which relate to the acquisition of leasehold interests, are assessed for impairment on a property-by-property basis for individually significant balances and on an aggregate basis for individually insignificant balances. If the assessment indicates impairment, a loss is recognized by providing a valuation allowance at the level at which impairment was assessed. The impairment assessment is affected by economic factors such as the results of exploration activities, commodity price outlooks, remaining lease terms, and potential shifts in business strategy employed by management. In the case of individually insignificant balances, the amount of the impairment loss recognized is determined by amortizing the portion of these properties’ costs which ENP believes will not be transferred to proved properties over the remaining life of the lease.
 
Amounts shown in the accompanying Consolidated Balance Sheets as “Proved properties, including wells and related equipment” consisted of the following as of the dates indicated:
 
                 
    December 31,  
    2009     2008  
    (In thousands)  
 
Proved leasehold costs
  $ 609,692     $ 580,695  
Wells and related equipment — Completed
    241,953       227,970  
Wells and related equipment — In process
    188       6,238  
                 
Total proved properties
  $ 851,833     $ 814,903  
                 
 
Other Property and Equipment.  Other property and equipment is carried at cost. Depreciation is expensed on a straight-line basis over estimated useful lives, which range from three to seven years. Gains or losses from the disposal of other property and equipment are recognized in the period realized and included in “Other operating expense” in the accompanying Consolidated Statements of Operations.
 
Goodwill and Other Intangible Assets
 
ENP accounts for goodwill and other intangible assets under the provisions of ASC 350, 730-10-60-3, 323-10-35-13, 205-20-60-4, and 280-10-60-2 (formerly SFAS No. 142, “Goodwill and Other Intangible Assets”). Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in business combinations. Goodwill is tested for impairment annually on December 31 or whenever indicators of impairment exist. The goodwill test is performed at the reporting unit level. ENP has determined that it has only one reporting unit, which is oil and natural gas production in the United States. If indicators of impairment are determined to exist, an impairment charge is recognized for the amount by which the carrying value of goodwill exceeds its implied fair value.


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
ENP utilizes both a market capitalization and an income approach to determine the fair value of its reporting units. The primary component of the income approach is the estimated discounted future net cash flows expected to be recovered from the reporting unit’s oil and natural gas properties. ENP’s analysis concluded that there was no impairment of goodwill as of December 31, 2009. Significant decreases in the prices of oil and natural gas or significant negative reserve adjustments from the December 31, 2009 assessment could change ENP’s estimates of the fair value of its reporting units and could result in an impairment charge.
 
Intangible assets with definite useful lives are amortized over their estimated useful lives. In accordance with ASC 410-20, 450-20, 835-20, 360-10-35, 840-10, and 980-410, ENP evaluates the recoverability of intangible assets with definite useful lives whenever events or changes in circumstances indicate that the carrying value of the asset may not be fully recoverable. An impairment loss exists when the estimated undiscounted cash flows expected to result from the use of the asset and its eventual disposition are less than its carrying amount.
 
ENP is a party to a contract allowing it to purchase a certain amount of natural gas at a below market price for use as field fuel. As of December 31, 2009, the gross carrying value of this contact was $4.2 million and accumulated amortization was $0.9 million. During each of 2009, 2008, and 2007, ENP recorded approximately $0.3 million of amortization expense related to this contract. The net carrying value is shown as “Other intangibles, net” on the accompanying Consolidated Balance Sheets and is being amortized on a straight-line basis through November 2020. ENP expects to recognize $0.3 million of amortization expense during each of the next five years related to this contract.
 
Asset Retirement Obligations
 
In accordance with ASC 410-20, 450-20, 835-20, 360-10-35, 840-10, and 980-410 (formerly SFAS No. 143, “Accounting for Asset Retirement Obligations”), ENP recognizes the fair value of a liability for an asset retirement obligation in the period in which the liability is incurred. For oil and natural gas properties, this is the period in which the property is acquired or a new well is drilled. An amount equal to and offsetting the liability is capitalized as part of the carrying amount of ENP’s oil and natural gas properties. The liability is recorded at its discounted risk adjusted fair value and then accreted each period until it is settled or the asset is sold, at which time the liability is reversed. Estimates are based on historical experience in plugging and abandoning wells and estimated remaining field life based on reserve estimates. Please read “Note 5. Asset Retirement Obligations” for additional information.
 
Unit-Based Compensation
 
ENP does not have any employees. However, the LTIP allows for the grant of unit awards and unit-based awards for employees, consultants, and directors of EAC, the General Partner, and any of their affiliates that perform services for ENP. ENP accounts for unit-based compensation according to the provisions of ASC 718, 505-50, and 260-10-60-1A (formerly SFAS No. 123 (revised 2004), “Share-Based Payment”), which requires the recognition of compensation expense for unit-based awards over the requisite service period in an amount equal to the grant date fair value of the awards. Please read “Note 9. Unit-Based Compensation Plans” for additional discussion of ENP’s unit-based compensation plans.
 
Segment Reporting
 
ENP operates in only one industry: the oil and natural gas exploration and production industry in the United States. All revenues are derived from customers located in the United States.


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Major Customers / Concentration of Credit Risk
 
The following purchasers accounted for 10 percent or greater of the sales of production for the period indicated:
 
                         
    Percentage of Total Sales of
    Production for the Year Ended
    December 31,
Purchaser
  2009   2008   2007
 
Marathon Oil Corporation
    43 %     19 %     24 %
ConocoPhillips
    (a )     17 %     10 %
Tesoro Refining & Marketing Co
    (a )     15 %     17 %
 
 
(a) Less than 10 percent for the period indicated.
 
Income Taxes
 
ENP is treated as a partnership for federal and state income tax purposes with each partner being separately taxed on his share of ENP’s taxable income. Therefore, no provision for current or deferred federal income taxes has been provided for in the accompanying consolidated financial statements. However, the portion of ENP’s operations that is located in Texas is subject to an entity-level tax, the Texas margin tax, at an effective rate of up to 0.7 percent of income that is apportioned to Texas beginning with tax reports due on or after January 1, 2008. Deferred tax assets and liabilities are recognized for future Texas margin tax consequences attributable to differences between financial statement carrying amounts of existing assets and liabilities and their respective Texas margin tax bases.
 
Net income for financial statement purposes may differ significantly from taxable income reportable to unitholders as a result of differences between the tax bases and financial reporting bases of assets and liabilities and the taxable income allocation requirements under the partnership agreement. In addition, individual unitholders have different investment bases depending upon the timing and price of acquisition of their common units, and each unitholder’s tax accounting, which is partially dependent upon the unitholder’s tax position, differs from the accounting followed in the consolidated financial statements. As a result, the aggregate difference in the basis of net assets for financial and tax reporting purposes cannot be readily determined as ENP does not have access to information about each unitholder’s tax attributes in ENP.
 
ENP accounts for uncertainty in income taxes in accordance with ASC 740, 805-740, and 835-10 (formerly FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes — an Interpretation of FASB Statement No. 109”). ENP performs a periodic evaluation of tax positions to review the appropriate recognition threshold for each tax position recognized in its consolidated financial statements. As of December 31, 2009 and 2008, all of ENP’s tax positions met the “more-likely-than-not” threshold prescribed by ASC 740, 805-740, and 835-10. As a result, no additional tax expense, interest, or penalties have been accrued.
 
Oil and Natural Gas Revenue Recognition
 
Oil and natural gas revenues are recognized as oil and natural gas is produced and sold, net of royalties. Royalties and severance taxes are incurred based upon the actual price received from the sales. To the extent actual volumes and prices of oil and natural gas are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volumes and prices for those properties are estimated and recorded as “Accounts receivable — trade” in the accompanying Consolidated Balance Sheets. Natural gas revenues are reduced by any processing and other fees incurred except for transportation costs


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
paid to third parties, which are recorded as “Other operating expense” in the accompanying Consolidated Statements of Operations. Natural gas revenues are recorded using the sales method of accounting whereby revenue is recognized based on actual sales of natural gas rather than ENP’s proportionate share of natural gas production. If ENP’s overproduced imbalance position (i.e., ENP has cumulatively been over-allocated production) is greater than ENP’s share of remaining reserves, a liability is recorded for the excess at period-end prices unless a different price is specified in the contract in which case that price is used. Revenue is not recognized for the production in tanks, oil marketed on behalf of joint owners in ENP’s properties, or oil in pipelines that has not been delivered to the purchaser.
 
Natural gas imbalances at December 31, 2009 and 2008 were 15,139 million British thermal units (“MMBtu”) and 38,010 MMBtu, respectively, over-delivered to ENP, the value of which was approximately $0.1 million and $0.2 million, respectively.
 
Marketing Revenues and Expenses
 
In March 2007, ENP acquired a crude oil pipeline and a natural gas pipeline as part of the Big Horn Basin acquisition. Natural gas volumes are purchased from numerous gas producers at the inlet of the pipeline and resold downstream to various local and off-system markets. In addition, pipeline tariffs are collected for transportation through the crude oil pipeline.
 
Marketing revenues includes the sales of oil and natural gas purchased from third parties, as well as pipeline tariffs charged for transportation volumes through ENP’s pipelines. Marketing revenues derived from sales of oil or natural gas purchased from third parties are recognized when persuasive evidence of a sales arrangement exists, delivery has occurred, the sales price is fixed or determinable, and collectibility is reasonably assured. As ENP takes title to the oil and natural gas and has risks and rewards of ownership, these transactions are presented gross in the accompanying Consolidated Statements of Operations, unless they meet the criteria for netting as outlined in ASC 845-10 (formerly Emerging Issues Task Force (“EITF”) Issue No. 04-13,Accounting for Purchases and Sales of Inventory with the Same Counterparty”).
 
Shipping Costs
 
Shipping costs in the form of pipeline fees and trucking costs paid to third parties are incurred to transport oil and natural gas production from certain properties to a different market location for ultimate sale. These costs are included in “Other operating expense” and “Marketing expense,” as applicable, in the accompanying Consolidated Statements of Operations.
 
Derivatives
 
ENP uses various financial instruments for non-trading purposes to manage and reduce price volatility and other market risks associated with its oil and natural gas production. These arrangements are structured to reduce ENP’s exposure to commodity price decreases, but they can also limit the benefit ENP might otherwise receive from commodity price increases. ENP’s risk management activity is generally accomplished through over-the-counter derivative contracts with large financial institutions. ENP also use derivative instruments in the form of interest rate swaps, which hedge its risk related to interest rate fluctuation.
 
ENP applies the provisions of ASC 815 (formerly SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”), which requires each derivative instrument to be recorded in the balance sheet at fair value. If a derivative has not been designated as a hedge or does not otherwise qualify for hedge accounting, it must be adjusted to fair value through earnings. However, if a derivative qualifies for hedge accounting, depending on the nature of the hedge, the effective portion of changes in fair value can be recognized in accumulated other comprehensive income or loss until such time as the hedged item is recognized in earnings. In order to qualify for cash flow hedge accounting, the cash flows from the hedging instrument must be highly


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
effective in offsetting changes in cash flows of the hedged item. In addition, all hedging relationships must be designated, documented, and reassessed periodically.
 
ENP has elected to designate its outstanding interest rate swaps as cash flow hedges. The effective portion of the mark-to-market gain or loss on these derivative instruments is recorded in “Accumulated other comprehensive loss” on the accompanying Consolidated Balance Sheets and reclassified into earnings in the same period in which the hedged transaction affects earnings. Any ineffective portion of the mark-to-market gain or loss is recognized in earnings and included in “Derivative fair value loss (gain)” in the accompanying Consolidated Statements of Operations.
 
ENP has not elected to designate its current portfolio of commodity derivative contracts as hedges. Therefore, changes in fair value of these derivative instruments are recognized in earnings and included in “Derivative fair value loss (gain)” in the accompanying Consolidated Statements of Operations.
 
Earnings Per Unit
 
ENP’s net income (loss) is allocated to partner equity accounts in accordance with the provisions of the partnership agreement. For purposes of calculating earnings per unit, ENP allocates net income (loss) to its limited partners and participating securities, including general partner units, each quarter under the provisions of ASC 260-10 (formerly EITF Issue No. 03-6,Participating Securities and the Two {d208} Class Method under FASB Statement No. 128”). Under the two-class method of calculating earnings per unit, earnings are allocated to participating securities as if all the earnings for the period had been distributed. A participating security is any security that may participate in distributions with common units. For purposes of calculating earnings per unit, general partner units, unvested phantom units, and unvested management incentive units are considered participating securities. Net income (loss) per common unit is calculated by dividing the limited partners’ interest in net income (loss), after deducting the interests of participating securities, by the weighted average common units outstanding. Please read “New Accounting Pronouncements” below and “Note 8. Earnings Per Unit” for additional discussion.
 
Comprehensive Income (Loss)
 
ENP has elected to show comprehensive income (loss) as part of its Consolidated Statements of Partners’ Equity and Comprehensive Income (Loss) rather than in its Consolidated Statements of Operations or in a separate statement.
 
FASB Launches Accounting Standards Codification
 
In June 2009, the FASB issued ASC 105-10 (formerly SFAS No. 168, “The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles”). ASC 105-10 establishes the Codification as the sole source of authoritative accounting principles recognized by the FASB to be applied by all nongovernmental entities in the preparation of financial statements in conformity with GAAP. ASC 105-10 was prospectively effective for financial statements issued for fiscal years ending on or after September 15, 2009, and interim periods within those fiscal years. The adoption of ASC 105-10 on July 1, 2009 did not impact ENP’s results of operations or financial condition.
 
Following the Codification, the FASB does not issue new standards in the form of Statements, FASB Staff Positions (“FSP”), or EITF Abstracts. Instead, it issues Accounting Standards Updates (“ASU”), which update the Codification, provide background information about the guidance, and provide the basis for conclusions on the changes to the Codification.
 
The Codification did not change GAAP; however, it did change the way GAAP is organized and presented. As a result, these changes impact how companies, including ENP, reference GAAP in their financial statements and in their significant accounting policies.


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
New Accounting Pronouncements
 
ASC 820-10 (formerly FSP No. FAS 157-2, “Effective Date of FASB Statement No. 157”)
 
In February 2008, the FASB issued ASC 820-10, which delayed the effective date of ASC 820-10 for one year for nonfinancial assets and liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). ASC 820-10 was prospectively effective for financial statements issued for fiscal years beginning after November 15, 2008, and interim periods within those fiscal years. ENP elected a partial deferral of ASC 820-10 for all instruments within the scope of ASC 820-10, including, but not limited to, its asset retirement obligations and indefinite lived assets. The adoption of ASC 820-10 on January 1, 2009 as it relates to nonfinancial assets and liabilities did not have a material impact on ENP’s results of operations or financial condition. Please read “Note 10. Fair Value Measurements” for additional discussion.
 
ASC 805 (formerly SFAS No. 141 (revised 2007), “Business Combinations”)
 
In December 2007, the FASB issued ASC 805, which establishes principles and requirements for the reporting entity in a business combination, including: (1) recognition and measurement in the financial statements of the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree; (2) recognition and measurement of goodwill acquired in the business combination or a gain from a bargain purchase; and (3) determination of the information to be disclosed to enable financial statement users to evaluate the nature and financial effects of the business combination. In April 2009, the FASB issued ASC 805-20 (formerly FSP No. FAS 141(R)-1, “Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arises from Contingencies”), which amends and clarifies ASC 805 to address application issues, including: (1) initial recognition and measurement; (2) subsequent measurement and accounting; and (3) disclosure of assets and liabilities arising from contingencies in a business combination. ASC 805 and ASC 805-20 were prospectively effective for business combinations consummated in fiscal years beginning on or after December 15, 2008. The accounting for transactions between entities under common control is unchanged under ASC 805 and ASC 805-20. The application of ASC 805 and ASC 805-20 to the acquisition of certain oil and natural gas properties and related assets during 2009 was nominal. Please read “Note 3. Acquisitions” for additional discussion.
 
ASC 815-10 (formerly SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities — an amendment of FASB Statement No. 133”)
 
In March 2008, the FASB issued ASC 815-10, which requires enhanced disclosures: including (1) how and why an entity uses derivative instruments; (2) how derivative instruments and related hedged items are accounted for under ASC 815; and (3) how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. ASC 815-10 was prospectively effective for financial statements issued for fiscal years beginning on or after November 15, 2008, and interim periods within those fiscal years. The adoption of ASC 815-10 on January 1, 2009 required additional disclosures regarding ENP’s derivative instruments; however, it did not impact ENP’s results of operations or financial condition. Please read “Note 10. Fair Value Measurements” for additional discussion.
 
ASC 260-10 (formerly EITF Issue No. 07-4, “Application of the Two-Class Method under FASB Statement No. 128, Earnings per Share, to Master Limited Partnerships”)
 
In March 2008, the FASB issued ASC 260-10, which addresses how master limited partnerships should calculate earnings per unit using the two-class method and how current period earnings of a master limited partnership should be allocated to the general partner, limited partners, and other participating securities. ASC 260-10 was retrospectively effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those years. In the accompanying Consolidated Financial Statements,


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
periods prior to the adoption of ASC 260-10 have been restated to calculate earnings per unit in accordance with this pronouncement. The retrospective application of ASC 260-10 reduced ENP’s basic and diluted earnings per common unit by $0.01 for the year ended December 31, 2007. The adoption of ASC 260-10 did not have an impact on ENP’s basic or diluted earnings per common unit for the year ended December 31, 2008. Please read “Note 8. Earnings Per Unit” for additional discussion.
 
ASC 260-10 (formerly FSP No. EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities”)
 
In June 2008, the FASB issued ASC 260-10, which addresses whether instruments granted in unit-based payment transactions are participating securities prior to vesting and, therefore, need to be included in the earnings allocation for computing basic earnings per unit under the two-class method. ASC 260-10 was retroactively effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those years. In the accompanying Consolidated Financial Statements, periods prior to the adoption of ASC 260-10 have been restated to calculate earnings per unit in accordance with this pronouncement. Please read “Note 8. Earnings Per Unit” for additional discussion.
 
SEC Release No. 33-8995, “Modernization of Oil and Gas Reporting” (“Release 33-8995”)
 
In December 2008, the United States Securities and Exchange Commission (the “SEC”) issued Release 33-8995, which amends oil and natural gas reporting requirements under Regulations S-K and S-X. Release 33-8995 also adds a section to Regulation S-K (Subpart 1200) to codify the revised disclosure requirements in Securities Act Industry Guide 2, which is being phased out. Release 33-8995 permits the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes. Release 33-8995 will also allow companies to disclose their probable and possible reserves to investors at the company’s option. In addition, the new disclosure requirements require companies to: (1) report the independence and qualifications of its reserves preparer or auditor; (2) file reports when a third party is relied upon to prepare reserves estimates or conduct a reserves audit; and (3) report oil and gas reserves using an average price based upon the prior 12-month period rather than a year-end price, unless prices are defined by contractual arrangements, excluding escalations based on future conditions. Release 33-8995 was prospectively effective for financial statements issued for fiscal years ending on or after December 31, 2009.
 
ASC 855-10 (formerly SFAS No. 165, “Subsequent Events”)
 
In June 2009, the FASB issued ASC 855-10 to establish general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or available to be issued. In particular, ASC 855-10 sets forth: (1) the period after the balance sheet date during which management of a reporting entity should evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements; (2) the circumstances under which an entity should recognize events or transactions occurring after the balance sheet date in its financial statements; and (3) the disclosures that an entity should make about events or transactions that occurred after the balance sheet date. ASC 855-10 was prospectively effective for financial statements issued for interim or annual periods ending after June 15, 2009. The adoption of ASC 855-10 on June 30, 2009 did not impact ENP’s results of operations or financial condition.
 
ASU No. 2009-05, “Fair Value Measurement and Disclosure: Measuring Liabilities at Fair Value” (“ASU 2009-05”)
 
In August 2009, the FASB issued ASU 2009-05 to provide clarification on measuring liabilities at fair value when a quoted price in an active market is not available. In particular, ASU 2009-05 specifies that a


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
valuation technique should be applied that used either the quote of the liability when traded as an asset, the quoted prices for similar liabilities or similar liabilities when traded as assets, or another valuation technique consistent with existing fair value measurement guidance. ASU 2009-05 was prospectively effective for financial statements issued for interim or annual periods ending after October 1, 2009. The adoption of ASU 2009-05 on December 31, 2009 did not impact ENP’s results of operations or financial condition.
 
ASU No. 2010-03, “Oil and Gas Reserve Estimation and Disclosure” (“ASU 2010-03”)
 
In January 2010, the FASB issued ASU 2010-03 to align the oil and natural gas reserve estimation and disclosure requirements of Extractive Activities — Oil and Gas (ASC 932) with the requirements in the SEC’s final rule, “Modernization of the Oil and Gas Reporting.” ASU 2010-03 was prospectively effective for financial statements issued for annual periods ending on or after December 31, 2009.
 
ASU No. 2010-06, “Improving Disclosures about Fair Value Measurements” (“ASU 2010-06”)
 
In January 2010, the FASB issued ASU 2010-06 to require additional information to be disclosed principally in respect of level 3 fair value measurements and transfers to and from Level 1 and Level 2 measurements; in addition, enhanced disclosure is required concerning inputs and valuation techniques used to determine Level 2 and Level 3 fair value measurements. ASU 2010-06 was generally effective for interim and annual reporting periods beginning after December 15, 2009; however, the requirements to disclose separately purchases, sales, issuances, and settlements in the Level 3 reconciliation are effective for fiscal years beginning after December 15, 2010 (and for interim periods within such years) with early adoption allowed. The adoption of ASU 2010-06 on December 31, 2009 did not impact ENP’s results of operations or financial condition.
 
Note 3.   Acquisitions
 
Rockies and Permian Basin Assets
 
In August 2009, ENP acquired the Rockies and Permian Basin Assets from Encore Operating for approximately $179.6 million in cash, which was financed through borrowings under OLLC’s revolving credit facility and proceeds from the issuance of ENP common units to the public. As previously discussed, the acquisition was accounted for as a transaction between entities under common control. Therefore, the assets and liabilities of the acquired properties were recorded at Encore Operating’s carrying value as of July 31, 2009 of approximately $194.4 million and $4.2 million, respectively, and the historical financial information of ENP was recast to include the Rockies and Permian Basin Assets for all periods the properties were owned by Encore Operating. As the historical basis in the Rockies and Permian Basin Assets is included in the accompanying Consolidated Balance Sheets, the cash purchase price was recorded as a deemed distribution when paid to EAC.
 
Williston Basin Assets
 
In June 2009, ENP acquired the Williston Basin Assets from Encore Operating for approximately $25.2 million in cash, which was financed through borrowings under OLLC’s revolving credit facility and proceeds from the issuance of ENP common units to the public. As previously discussed, the acquisition was accounted for as a transaction between entities under common control. Therefore, the assets and liabilities of the acquired properties were recorded at Encore Operating’s carrying value as of May 31, 2009 of approximately $31.9 million and $1.3 million, respectively, and the historical financial information of ENP was recast to include the Williston Basin Assets for all periods the properties were owned by Encore Operating. As the historical basis in the Williston Basin Assets is included in the accompanying Consolidated Balance Sheets, the cash purchase price was recorded as a deemed distribution when paid to EAC.


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ENCORE ENERGY PARTNERS LP
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Vinegarone Assets
 
In May 2009, ENP acquired certain natural gas properties in the Vinegarone Field in Val Verde County, Texas (the “Vinegarone Assets”) from an independent energy company for approximately $27.5 million in cash, which was financed through proceeds from the issuance of ENP common units to the public. The results of operations of the Vinegarone Assets are included with those of ENP from the date of acquisition forward.
 
Arkoma Basin Assets
 
In January 2009, ENP acquired the Arkoma Basin Assets from Encore Operating for approximately $46.4 million in cash, which was financed through borrowings under OLLC’s revolving credit facility. As previously discussed, the acquisition was accounted for as a transaction between entities under common control. Therefore, the assets and liabilities of the acquired properties were recorded at Encore Operating’s carrying value as of December 31, 2008 of approximately $18.1 million and $0.7 million, respectively, and the historical financial information of ENP was recast to include the Arkoma Basin Assets for all periods the properties were owned by Encore Operating. As the historical basis in the Arkoma Basin Assets is included in the accompanying Consolidated Balance Sheets, the cash purchase price was recorded as a deemed distribution when paid to EAC.
 
Permian and Williston Basin Assets
 
In February 2008, ENP acquired the Permian and Williston Basin Assets from Encore Operating for approximately $125.0 million in cash and the issuance of 6,884,776 ENP common units to Encore Operating. In determining the total purchase price, the common units were valued at $125.0 million. However, no accounting value was ascribed to the common units as the cash consideration exceeded Encore Operating’s carrying value of the properties. The cash portion of the purchase price was financed through borrowings under OLLC’s revolving credit facility. As previously discussed, the acquisition was accounted for as a transaction between entities under common control. Therefore, the assets and liabilities of the acquired properties were recorded at Encore Operating’s carrying value as of December 31, 2007 of approximately $105.0 million and $5.1 million, respectively, and the historical financial information of ENP was recast to include the Permian and Williston Basin Assets for all periods the properties were owned by Encore Operating. As the historical basis in the Permian and Williston Basin Assets is included in the accompanying Consolidated Balance Sheets, the cash purchase price was recorded as a deemed distribution when paid to EAC.
 
In May 2008, ENP acquired an existing net profits interest in certain of its properties in the Permian Basin in West Texas from an independent energy company for 283,700 ENP common units, which were valued at approximately $5.8 million at the time of the acquisition.
 
Big Horn Basin Assets
 
In March 2007, EAC acquired certain oil and natural gas properties and related assets in the Big Horn Basin in Wyoming and Montana (the “Big Horn Basin Assets”) from an independent energy company. Prior to closing, EAC assigned the rights and duties under the purchase and sale agreement relating to the Elk Basin Assets to ENP. The purchase price for the Elk Basin Assets was approximately $330.7 million in cash. The results of operations of the Big Horn Basin Assets are included with those of ENP from the date of acquisition forward.
 
ENP financed the acquisition of the Elk Basin Assets through a $93.7 million contribution from EAC, $120 million of borrowings under a subordinated credit agreement with EAP Operating, and borrowings under OLLC’s revolving credit facility. Please read “Note 6. Long-Term Debt” for additional discussion of ENP’s long-term debt.


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ENCORE ENERGY PARTNERS LP
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
The following unaudited pro forma condensed financial data for 2007 (in thousands, except per unit amounts) was derived from the historical financial statements of ENP and from the accounting records of the seller to give effect to the acquisition of the Elk Basin Assets as if it had occurred on January 1, 2007. The unaudited pro forma condensed financial information has been included for comparative purposes only and is not necessarily indicative of the results that might have occurred had the acquisition of the Elk Basin Assets taken place on January 1, 2007 and is not intended to be a projection of future results.
 
         
Pro forma total revenues
  $ 197,408  
         
Pro forma net income
  $ 19,621  
         
Pro forma net loss per common unit:
       
Basic
  $ (0.79 )
Diluted
  $ (0.79 )
 
Note 4.   Commitments and Contingencies
 
Litigation
 
ENP is a party to ongoing legal proceedings in the ordinary course of business. The General Partner’s management does not believe the result of these proceedings will have a material adverse effect on ENP’s business, financial position, results of operations, liquidity, or ability to pay distributions.
 
Leases
 
ENP leases equipment that have non-cancelable lease terms in excess of one year. The following table summarizes by year the remaining non-cancelable future payments under these operating leases as of December 31, 2009 (in thousands):
 
         
2010
  $ 687  
2011
    687  
2012
    514  
2013
     
2014
     
Thereafter
     
         
    $ 1,888  
         
 
ENP’s operating lease rental expense was approximately $1.1 million, $1.0 million, and $1.1 million in 2009, 2008, and 2007, respectively.
 
Note 5.   Asset Retirement Obligations
 
Asset retirement obligations relate to future plugging and abandonment expenses on oil and natural gas properties and related facilities disposal. The following table summarizes the changes in ENP’s asset retirement obligations for the periods indicated:
 
                 
    Year Ended December 31,  
    2009     2008  
    (In thousands)  
 
Future abandonment liability at January 1
  $ 12,376     $ 11,254  
Acquisition of properties
    67        
Wells drilled
    22       104  
Accretion of discount
    709       538  
Plugging and abandonment costs incurred
    (164 )     (62 )
Revision of previous estimates
    120       542  
                 
Future abandonment liability at December 31
  $ 13,130     $ 12,376  
                 


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ENCORE ENERGY PARTNERS LP
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
As of December 31, 2009, $12.6 million of ENP’s asset retirement obligations were long-term and recorded in “Future abandonment cost, net of current portion” and $0.6 million were current and included in “Other current liabilities” in the accompanying Consolidated Balance Sheets. Approximately $4.7 million of the long-term future abandonment liability represents the estimated cost for decommissioning the Elk Basin natural gas processing plant.
 
Note 6.   Long-Term Debt
 
Revolving Credit Facility
 
OLLC is a party to a five-year credit agreement dated March 7, 2007 (as amended, the “OLLC Credit Agreement”). The OLLC Credit Agreement matures on March 7, 2012. In March 2009, OLLC amended the OLLC Credit Agreement to, among other things, increase the interest rate margins and commitment fees applicable to loans made under the OLLC Credit Agreement. In August 2009, OLLC amended the OLLC Credit Agreement to, among other things, (1) increase the borrowing base from $240 million to $375 million, (2) increase the aggregate commitments of the lenders from $300 million to $475 million, and (3) increase the interest rate margins and commitment fees applicable to loans made under the OLLC Credit Agreement. In November 2009, OLLC amended the OLLC Credit Agreement, which will be effective upon the closing of the Merger, to, among other things, permit the consummation of the Merger from being a “Change of Control” under the OLLC Credit Agreement.
 
The OLLC Credit Agreement provides for revolving credit loans to be made to OLLC from time to time and letters of credit to be issued from time to time for the account of OLLC or any of its restricted subsidiaries. The aggregate amount of the commitments of the lenders under the OLLC Credit Agreement is $475 million. Availability under the OLLC Credit Agreement is subject to a borrowing base, which is redetermined semi-annually and upon requested special redeterminations. As of December 31, 2009, the borrowing base was $375 million and there were $255 million of outstanding borrowings and $120 million of borrowing capacity under the OLLC Credit Agreement.
 
OLLC incurs a commitment fee of 0.5 percent on the unused portion of the OLLC Credit Agreement.
 
Obligations under the OLLC Credit Agreement are secured by a first-priority security interest in substantially all of OLLC’s proved oil and natural gas reserves and in the equity interests of OLLC and its restricted subsidiaries. In addition, obligations under the OLLC Credit Agreement are guaranteed by ENP and OLLC’s restricted subsidiaries. Obligations under the OLLC Credit Agreement are non-recourse to EAC and its restricted subsidiaries.
 
Loans under the OLLC Credit Agreement are subject to varying rates of interest based on (1) amount outstanding in relation to the borrowing base and (2) whether the loan is a Eurodollar loan or a base rate loan. Eurodollar loans under the OLLC Credit Agreement bear interest at the Eurodollar rate plus the applicable margin indicated in the following table, and base rate loans under the OLLC Credit Agreement bear interest at the base rate plus the applicable margin indicated in the following table:
 
                 
    Applicable Margin for
  Applicable Margin for
Ratio of Outstanding Borrowings to Borrowing Base
  Eurodollar Loans   Base Rate Loans
 
Less than .50 to 1
    2.250 %     1.250 %
Greater than or equal to .50 to 1 but less than .75 to 1
    2.500 %     1.500 %
Greater than or equal to .75 to 1 but less than .90 to 1
    2.750 %     1.750 %
Greater than or equal to .90 to 1
    3.000 %     2.000 %
 
The “Eurodollar rate” for any interest period (either one, two, three, or six months, as selected by ENP) is the rate equal to the British Bankers Association London Interbank Offered Rate (“LIBOR”) for deposits in dollars for a similar interest period. The “Base Rate” is calculated as the highest of: (1) the annual rate of


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ENCORE ENERGY PARTNERS LP
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
interest announced by Bank of America, N.A. as its “prime rate”; (2) the federal funds effective rate plus 0.5 percent; or (3) except during a “LIBOR Unavailability Period,” the Eurodollar rate (for dollar deposits for a one-month term) for such day plus 1.0 percent.
 
Any outstanding letters of credit reduce the availability under the OLLC Credit Agreement. Borrowings under the OLLC Credit Agreement may be repaid from time to time without penalty.
 
The OLLC Credit Agreement contains covenants including, among others, the following:
 
  •  a prohibition against incurring debt, subject to permitted exceptions;
 
  •  a prohibition against purchasing or redeeming capital stock, or prepaying indebtedness, subject to permitted exceptions;
 
  •  a restriction on creating liens on the assets of ENP, OLLC, and OLLC’s restricted subsidiaries, subject to permitted exceptions;
 
  •  restrictions on merging and selling assets outside the ordinary course of business;
 
  •  restrictions on use of proceeds, investments, transactions with affiliates, or change of principal business;
 
  •  a provision limiting oil and natural gas hedging transactions (other than puts) to a volume not exceeding 75 percent of anticipated production from proved producing reserves;
 
  •  a requirement that ENP and OLLC maintain a ratio of consolidated current assets to consolidated current liabilities of not less than 1.0 to 1.0;
 
  •  a requirement that ENP and OLLC maintain a ratio of consolidated EBITDA to the sum of consolidated net interest expense plus letter of credit fees of not less than 2.5 to 1.0; and
 
  •  a requirement that ENP and OLLC maintain a ratio of consolidated funded debt to consolidated adjusted EBITDA of not more than 3.5 to 1.0.
 
As of December 31, 2009, ENP and OLLC were in compliance with all covenants of the OLLC Credit Agreement.
 
The OLLC Credit Agreement contains customary events of default including, among others, the following:
 
  •  failure to pay principal on any loan when due;
 
  •  failure to pay accrued interest on any loan or fees when due and such failure continues for more than three days;
 
  •  failure to observe or perform covenants and agreements contained in the OLLC Credit Agreement, subject in some cases to a 30-day grace period after discovery or notice of such failure;
 
  •  failure to make a payment when due on any other debt in a principal amount equal to or greater than $3 million or any other event or condition occurs which results in the acceleration of such debt or entitles the holder of such debt to accelerate the maturity of such debt;
 
  •  the commencement of liquidation, reorganization, or similar proceedings with respect to OLLC or any guarantor under bankruptcy or insolvency law, or the failure of OLLC or any guarantor generally to pay its debts as they become due;
 
  •  the entry of one or more judgments in excess of $3 million (to the extent not covered by insurance) and such judgment(s) remain unsatisfied and unstayed for 30 days;
 
  •  the occurrence of certain ERISA events involving an amount in excess of $3 million;


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ENCORE ENERGY PARTNERS LP
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
 
  •  there cease to exist liens covering at least 80 percent of the borrowing base properties; or
 
  •  the occurrence of a change in control.
 
If an event of default occurs and is continuing, lenders with a majority of the aggregate commitments may require Bank of America, N.A. to declare all amounts outstanding under the OLLC Credit Agreement to be immediately due and payable.
 
Subordinated Credit Agreement
 
In March 2007, OLLC entered into a six-year subordinated credit agreement with EAP Operating pursuant to which a single subordinated term loan was made to ENP in the aggregate amount of $120 million. The total outstanding balance of $126.4 million, including accrued interest, was repaid in September 2007 using a portion of the net proceeds from the IPO at which point the credit agreement was terminated.
 
Long-Term Debt Maturities
 
The following table shows ENP’s long-term debt maturities as of December 31, 2009:
 
                                                         
    Payments Due by Period
    Total   2010   2011   2012   2013   2014   Thereafter
    (In thousands)
 
Revolving credit facility
  $ 255,000     $     $     $ 255,000     $     $     $  
 
During 2009, 2008, and 2007, the weighted average interest rate for total indebtedness was 5.0 percent, 4.8 percent, and 8.9 percent, respectively.
 
Note 7.   Partners’ Equity and Distributions
 
Distributions
 
ENP’s partnership agreement requires that, within 45 days after the end of each quarter, it distribute all of its available cash (as defined in ENP’s partnership agreement) to its unitholders. Distributions are not cumulative. ENP distributes available cash to its unitholders in accordance with their ownership percentages.
 
The following table provides information regarding ENP’s distributions of available cash for the periods indicated:
 
                                 
        Cash Distribution
       
    Date
  Declared per
      Total
2009
  Declared   Common Unit   Date Paid   Distribution
                (In thousands)
 
Quarter ended December 31
    1/25/2010     $ 0.5375       2/12/2010     $ 24,642  
Quarter ended September 30
    10/26/2009     $ 0.5375       11/13/2009       24,642  
Quarter ended June 30
    7/27/2009     $ 0.5125       8/14/2009       23,481  
Quarter ended March 31
    4/27/2009     $ 0.5000       5/15/2009       16,813  
                                 
2008
                               
Quarter ended December 31
    1/26/2009     $ 0.5000       2/13/2009       16,813  
Quarter ended September 30
    11/7/2008     $ 0.6600       11/14/2008       22,191  
Quarter ended June 30
    8/11/2008     $ 0.6881       8/14/2008       23,119  
Quarter ended March 31
    5/9/2008     $ 0.5755       5/15/2008       19,316  
                                 
2007
                               
Quarter ended December 31
    2/6/2008     $ 0.3875       2/14/2008       9,843  
Quarter ended September 30
    11/8/2007     $ 0.0530 (a)     11/14/2007       1,346  
 
 
(a) Based on an initial quarterly distribution of $0.35 per unit, prorated for the period from and including September 17, 2007 (the closing date of the IPO) through September 30, 2007.


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ENCORE ENERGY PARTNERS LP
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
 
Shelf Registration Statement on Form S-3
 
In November 2008, ENP’s “shelf” registration statement on Form S-3 was declared effective by the SEC. Under the shelf registration statement, ENP may offer common units, senior debt, or subordinated debt in one or more offerings with a total initial offering price of up to $1 billion.
 
Public Offerings of Common Units
 
In July 2009, ENP issued 9,430,000 common units under its shelf registration statement at a price to the public of $14.30 per common unit. ENP used the net proceeds of approximately $129.2 million, after deducting the underwriters’ discounts and commissions of $5.4 million, in the aggregate, and offering costs of approximately $0.2 million, to fund a portion of the purchase price of the Rockies and Permian Basin Assets.
 
In May 2009, ENP issued 2,760,000 common units under its shelf registration statement at a price to the public of $15.60 per common unit. ENP used the net proceeds of approximately $40.9 million, after deducting the underwriters’ discounts and commissions of $1.9 million, in the aggregate, and offering costs of approximately $0.2 million, to fund the purchase price of the Vinegarone Assets and a portion of the purchase price of the Williston Basin Assets.
 
Note 8.   Earnings Per Unit
 
As discussed in “Note 2. Summary of Significant Accounting Policies,” ENP adopted ASC 260-10 on January 1, 2009 and all periods prior to adoption have been restated to calculate earnings per unit in accordance therewith. For 2008, basic earnings per unit and diluted earnings per unit were unaffected by the adoption of ASC 260-10. For 2007, basic earnings per unit and diluted earnings per unit each decreased $0.01 per common unit as a result of the adoption of ASC 260-10. For 2007, earnings per unit was calculated based on the net loss for the period from the closing of the IPO in September 2007 through December 31, 2007.


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ENCORE ENERGY PARTNERS LP
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
The following table reflects the allocation of net income (loss) to ENP’s limited partners and earnings per unit computations for the periods indicated:
 
                         
    Year Ended December 31,  
    2009     2008     2007  
    (In thousands, except per unit amounts)  
 
Net income (loss)
  $ (40,329 )   $ 220,756     $ 21,706  
Less: net income for pre-IPO and pre-partnership operations of assets acquired from affiliates
    (176 )     (51,640 )     (40,682 )
                         
Net income (loss) attributable to unitholders
  $ (40,505 )   $ 169,116     $ (18,976 )
                         
Numerator:
                       
Numerator for basic EPU:
                       
Net income (loss) attributable to unitholders
  $ (40,505 )   $ 169,116     $ (18,976 )
Less: distributions earned by participating securities
    (1,054 )     (4,498 )     (517 )
Plus: cash distributions in excess of (less than) income allocated to the general partner
    1,646       (1,548 )     616  
                         
Net income (loss) allocated to limited partners
    (39,913 )     163,070       (18,877 )
Plus: income allocated to dilutive participating securities
          3,398        
                         
Numerator for diluted EPU
  $ (39,913 )   $ 166,468     $ (18,877 )
                         
Denominator:
                       
Denominator for basic EPU:
                       
Weighted average common units outstanding
    39,366       30,568       23,877  
Effect of dilutive management incentive units(a)
          1,367        
Effect of dilutive phantom units(b)
          3        
                         
Denominator for diluted EPU
    39,366       31,938       23,877  
                         
Net income (loss) per common unit:
                       
Basic
  $ (1.01 )   $ 5.33     $ (0.79 )
Diluted
  $ (1.01 )   $ 5.21     $ (0.79 )
 
 
(a) For 2007, 550,000 management incentive units were outstanding but were excluded from the diluted earnings per unit calculations because their effect would have been antidilutive. Please read “Note 9. Unit-Based Compensation Plans” for additional discussion of the management incentive units.
 
(b) Unvested phantom units have no contractual obligation to absorb losses of ENP. Therefore, for 2009 and 2007, 56,250 and 20,000 phantom units, respectively, were outstanding but were excluded from the diluted earnings per unit calculations because their effect would have been antidilutive. Please read “Note 9. Unit-Based Compensation Plans” for additional discussion of phantom units.
 
Note 9.   Unit-Based Compensation Plans
 
Management Incentive Units
 
In May 2007, the board of directors of the General Partner issued 550,000 management incentive units to certain executive officers of the General Partner. During the fourth quarter of 2008, the management incentive units became convertible into ENP common units, at the option of the holder, at a ratio of one management incentive unit to approximately 3.1186 ENP common units, and all 550,000 management incentive units were converted into 1,715,205 ENP common units.


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ENCORE ENERGY PARTNERS LP
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
The fair value of the management incentive units was estimated on the date of grant using a discounted dividend model. During 2008 and 2007, ENP recognized non-cash unit-based compensation expense for the management incentive units of approximately $4.8 million and $6.8 million, respectively, which is included in “General and administrative expense” in the accompanying Consolidated Statements of Operations. There have been no additional issuances of management incentive units.
 
Long-Term Incentive Plan
 
In September 2007, the board of directors of the General Partner adopted the LTIP, which provides for the granting of options, restricted units, phantom units, unit appreciation rights, distribution equivalent rights, other unit-based awards, and unit awards. All employees, consultants, and directors of EAC, the General Partner, and any of their subsidiaries and affiliates who perform services for ENP are eligible to be granted awards under the LTIP. The LTIP is administered by the board of directors of the General Partner or a committee thereof, referred to as the plan administrator. To satisfy common unit awards under the LTIP, ENP may issue common units, acquire common units in the open market, or use common units owned by EAC.
 
The total number of common units reserved for issuance pursuant to the LTIP is 1,150,000. As of December 31, 2009, there were 1,075,000 common units available for issuance under the LTIP.
 
Phantom Units.  Each October, ENP issues 5,000 phantom units to each member of the General Partner’s board of directors pursuant to the LTIP. A phantom unit entitles the grantee to receive a common unit upon the vesting of the phantom unit or, at the discretion of the plan administrator, cash equivalent to the value of a common unit. ENP intends to settle the phantom units at vesting by issuing common units to the grantee; therefore, these phantom units are classified as equity instruments. Phantom units vest equally over a four-year period. The holders of phantom units also receive distribution equivalent rights prior to vesting, which entitle them to receive cash equal to the amount of any cash distributions paid by ENP with respect to a common unit during the period the right is outstanding. During 2009, 2008, and 2007, ENP recognized non-cash unit-based compensation expense for the phantom units of approximately $0.4 million, $0.3 million, and $31,000, respectively, which is included in “General and administrative expense” in the accompanying Consolidated Statements of Operations.
 
The following table summarizes the changes in ENP’s unvested phantom units for 2009:
 
                 
          Weighted
 
          Average
 
    Number of
    Grant Date
 
    Shares     Fair Value  
 
Outstanding at January 1, 2009
    43,750     $ 18.67  
Granted
    25,000       18.13  
Vested
    (12,500 )     18.83  
Forfeited
           
                 
Outstanding at December 31, 2009
    56,250       18.40  
                 
 
During 2009, 2008, and 2007, ENP issued 25,000, 30,000, and 20,000, respectively, phantom units to members of the General Partner’s board of directors, the vesting of which is dependent only on the passage of


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ENCORE ENERGY PARTNERS LP
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
time and continuation as a board member. The following table provides information regarding ENP’s outstanding phantom units at December 31, 2009:
 
                                         
    Year of Vesting    
Year of Grant
  2010   2011   2012   2013   Total
 
2007
    5,000       5,000                   10,000  
2008
    7,500       7,500       6,250             21,250  
2009
    6,250       6,250       6,250       6,250       25,000  
                                         
Total
    18,750       18,750       12,500       6,250       56,250  
                                         
 
As of December 31, 2009, ENP had $0.7 million of total unrecognized compensation cost related to unvested phantom units, which is expected to be recognized over a weighted average period of 2.2 years. During 2009 and 2008, there were 12,500 and 6,250, respectively, phantom units that vested, the total fair value of which was $0.2 million and $0.1 million, respectively.
 
Note 10.   Fair Value Measurements
 
The following table sets forth ENP’s book value and estimated fair value of financial instruments as of the dates indicated:
 
                                 
    December 31,
    2009   2008
    Book
  Fair
  Book
  Fair
    Value   Value   Value   Value
    (In thousands)
 
Assets:
                               
Cash and cash equivalents
  $ 1,754     $ 1,754     $ 619     $ 619  
Accounts receivable — trade
    24,543       24,543       18,965       18,965  
Accounts receivable — affiliate
    8,213       8,213       3,896       3,896  
Commodity derivative contracts
    26,304       26,304       113,628       113,628  
Liabilities:
                               
Accounts payable — trade
    577       577       1,036       1,036  
Accounts payable — affiliate
    2,780       2,780       5,468       5,468  
Revolving credit facility
    255,000       255,000       150,000       150,000  
Commodity derivative contracts
    19,547       19,547       229       229  
Interest rate swaps
    3,669       3,669       4,559       4,559  
 
The book values of cash and cash equivalents, accounts receivable, and accounts payable approximate fair value due to the short-term nature of these instruments. The book value of the revolving credit facility approximates fair value as the interest rate is variable. ENP’s credit risk has not changed materially from the date the revolving credit facility was entered into. Commodity derivative contracts and interest rate swaps are marked-to-market each period and are thus stated at fair value in the accompanying Consolidated Balance Sheets.
 
Commodity Derivative Contracts
 
ENP manages commodity price risk with swap contracts, put contracts, collars, and floor spreads. Swap contracts provide a fixed price for a notional amount of sales volumes. Put contracts provide a fixed floor price on a notional amount of sales volumes while allowing full price participation if the relevant index price


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ENCORE ENERGY PARTNERS LP
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
closes above the floor price. Collars provide a floor price for a notional amount of sales volumes while allowing some additional price participation if the relevant index price closes above the floor price.
 
From time to time, ENP enters into floor spreads. In a floor spread, ENP purchases puts at a specified price (a “purchased put”) and also sells a put at a lower price (a “short put”). This strategy enables ENP to achieve some downside protection for a portion of its production, while funding the cost of such protection by selling a put at a lower price. If the price of the commodity falls below the strike price of the purchased put, then ENP has protection against additional commodity price decreases for the covered production down to the strike price of the short put. At commodity prices below the strike price of the short put, the benefit from the purchased put is generally offset by the expense associated with the short put. For example, in 2007, ENP purchased oil put options for 2,000 Bbls/D in 2010 at $65 per Bbl. As NYMEX prices increased in 2008, ENP wanted to protect downside price exposure at the higher price. In order to do this, ENP purchased oil put options for 2,000 Bbls/D in 2010 at $75 per Bbl and simultaneously sold oil put options for 2,000 Bbls/D in 2010 at $65 per Bbl. Thus, after these transactions were completed, ENP had purchased two oil put options for 2,000 Bbls/D in 2010 (one at $65 per Bbl and one at $75 per Bbl) and sold one oil put option for 2,000 Bbls/D in 2010 at $65 per Bbl. However, the net effect resulted in ENP owning one oil put option for 2,000 Bbls/D at $75 per Bbl. In the following tables, the purchased floor component of these floor spreads are shown net and included with ENP’s other floor contracts.
 
The following tables summarize ENP’s open commodity derivative contracts as of December 31, 2009:
 
Oil Derivative Contracts
 
                                                               
    Average
    Weighted
      Average
    Weighted
      Average
    Weighted
         
    Daily
    Average
      Daily
    Average
      Daily
    Average
      Asset (Liability)
 
    Floor
    Floor
      Cap
    Cap
      Swap
    Swap
      Fair Market
 
Period
  Volume     Price       Volume     Price       Volume     Price       Value  
    (Bbls)     (per Bbl)       (Bbls)     (per Bbl)       (Bbls)     (per Bbl)       (in thousands)  
2010
                                                        $ (1,476 )
      880     $ 80.00         440     $ 93.80         760     $ 75.43            
      2,000       75.00         1,000       77.23         250       65.95            
      760       67.00                                        
2011
                                                          2,638  
      1,880       80.00         1,440       95.41         760       78.46            
      1,000       70.00                                        
      760       65.00                       250       69.65            
2012
                                                          (5,020 )
      750       70.00         500       82.05         210       81.62            
      1,510       65.00         250       79.25         1,300       76.54            
                                                               
                                                          $ (3,858 )
                                                               


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ENCORE ENERGY PARTNERS LP
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Natural Gas Derivative Contracts
 
                                                               
    Average
    Weighted
      Average
    Weighted
      Average
    Weighted
         
    Daily
    Average
      Daily
    Average
      Daily
    Average
      Asset
 
    Floor
    Floor
      Cap
    Cap
      Swap
    Swap
      Fair Market
 
Period
  Volume     Price       Volume     Price       Volume     Price       Value  
    (Mcf)     (per Mcf)       (Mcf)     (per Mcf)       (Mcf)     (per Mcf)       (in thousands)  
2010
                                                        $ 7,963  
      3,800     $ 8.20         3,800     $ 9.58         5,452     $ 6.20            
      4,698       7.26                       550       5.86            
2011
                                                          2,105  
      3,398       6.31                       7,952       6.36            
                                  550       5.86            
2012
                                                          547  
      898       6.76                       5,452       6.26            
                                  550       5.86            
                                                               
                                                          $ 10,615  
                                                               
 
Counterparty Risk.  At December 31, 2009, ENP had committed 10 percent or greater (in terms of fair market value) of either its oil or natural gas derivative contracts in asset positions to the following counterparties:
 
                 
    Fair Market Value of
  Fair Market Value of
    Oil Derivative
  Natural Gas Derivative
    Contracts
  Contracts
Counterparty
  Committed   Committed
    (In thousands)
 
BNP Paribas
  $ 13,955     $ 2,795  
Calyon
    3,820       6,167  
Royal Bank of Canada
    4,158       (a )
Wachovia
    3,069       1,148  
 
 
(a) Less than 10 percent.
 
In order to mitigate the credit risk of financial instruments, ENP enters into master netting agreements with certain counterparties. The master netting agreement is a standardized, bilateral contract between a given counterparty and ENP. Instead of treating each financial transaction between the counterparty and ENP separately, the master netting agreement enables the counterparty and ENP to aggregate all financial trades and treat them as a single agreement. This arrangement is intended to benefit ENP in three ways: (1) the netting of the value of all trades reduces the likelihood of counterparties requiring daily collateral posting by ENP; (2) default by a counterparty under one financial trade can trigger rights to terminate all financial trades with such counterparty; and (3) netting of settlement amounts reduces ENP’s credit exposure to a given counterparty in the event of close-out. ENP’s accounting policy is to not offset fair value amounts for derivative instruments.
 
Interest Rate Swaps
 
ENP uses derivative instruments in the form of interest rate swaps, which hedge risk related to interest rate fluctuation, whereby it converts the interest due on certain floating rate debt under its revolving credit


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ENCORE ENERGY PARTNERS LP
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
facility to a weighted average fixed rate. The following table summarizes ENP’s open interest rate swaps as of December 31, 2009, all of which were entered into with Bank of America, N.A.:
 
                         
    Notional
  Fixed
  Floating
Term
  Amount   Rate   Rate
    (In thousands)        
 
Jan. 2010 — Jan. 2011
  $ 50,000       3.1610 %     1-month LIBOR  
Jan. 2010 — Jan. 2011
    25,000       2.9650 %     1-month LIBOR  
Jan. 2010 — Jan. 2011
    25,000       2.9613 %     1-month LIBOR  
Jan. 2010 — Mar. 2012
    50,000       2.4200 %     1-month LIBOR  
 
During 2009 and 2008, settlements of interest rate swaps increased ENP’s interest expense by approximately $3.8 million and $0.2 million, respectively.
 
Current Period Impact
 
ENP recognizes derivative fair value gains and losses related to: (1) ineffectiveness on derivative contracts designated as hedges; (2) changes in the fair market value of derivative contracts not designated as hedges; (3) settlements on derivative contracts not designated as hedges; and (4) premium amortization. The following table summarizes the components of “Derivative fair value loss (gain)” for the periods indicated:
 
                         
    Year Ended December 31,  
    2009     2008     2007  
    (In thousands)  
 
Ineffectiveness
  $ 2     $ 372     $  
Mark-to-market loss (gain)
    94,438       (101,595 )     23,470  
Premium amortization
    23,245       8,936       4,073  
Settlements
    (70,221 )     (4,593 )     (1,242 )
                         
Total derivative fair value loss (gain)
  $ 47,464     $ (96,880 )   $ 26,301  
                         
 
Accumulated Other Comprehensive Loss
 
At December 31, 2009 and 2008, “Accumulated other comprehensive loss” on the accompanying Consolidated Balance Sheets consisted entirely of deferred losses, net of tax, on ENP’s interest rate swaps of $3.4 million and $4.3 million, respectively. During 2010, ENP expects to reclassify $3.4 million of deferred losses from accumulated other comprehensive loss to interest expense. The actual gains or losses ENP will realize from its interest rate swaps may vary significantly from the deferred losses recorded in “Accumulated other comprehensive loss” in the accompanying Consolidated Balance Sheet due to the fluctuation of interest rates.


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ENCORE ENERGY PARTNERS LP
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Tabular Disclosures of Fair Value Measurements
 
The following table summarizes the fair value of ENP’s derivative contracts as of the dates indicated (in thousands):
 
                                                 
    Asset Derivatives     Liability Derivatives  
   
    December 31,
    December 31,
    December 31,
    December 31,
 
    2009     2008     2009     2008  
    Balance
        Balance
        Balance
        Balance
     
    Sheet
  Fair
    Sheet
  Fair
    Sheet
  Fair
    Sheet
  Fair
 
    Location   Value     Location   Value     Location   Value     Location   Value  
                                                 
Derivatives not designated as hedging instruments under ASC 815
                                               
                                                 
Commodity derivative contracts
  Derivatives — current   $ 12,881     Derivatives — current   $ 75,131     Derivatives — current   $ 6,393     Derivatives — current   $  
                                                 
Commodity derivative contracts
  Derivatives — noncurrent     13,423     Derivatives — noncurrent     38,497     Derivatives — noncurrent     13,154     Derivatives — noncurrent     229  
                                                 
                                                 
Total derivatives not designated as hedging instruments under ASC 815
      $ 26,304         $ 113,628         $ 19,547         $ 229  
                                                 
                                                 
Derivatives designated as hedging instruments under ASC 815
                                               
                                                 
Interest rate swaps
  Derivatives — current   $     Derivatives — current   $     Derivatives — current   $ 3,421     Derivatives — current   $ 1,297  
                                                 
Interest rate swaps
  Derivatives — noncurrent         Derivatives — noncurrent         Derivatives — noncurrent     248     Derivatives - noncurrent     3,262  
                                                 
                                                 
Total derivatives designated as hedging instruments under ASC 815
      $         $         $ 3,669         $ 4,559  
                                                 
                                                 
Total derivatives
      $ 26,304         $ 113,628         $ 23,216         $ 4,788  
                                                 
 
The following table summarizes the effect of derivative instruments not designated as hedges under ASC 815 on the Consolidated Statements of Operations for the periods indicated (in thousands):
 
                                 
        Amount of Loss (Gain)
        Recognized in Income
Derivatives Not Designated as
  Location of Loss (Gain)
  Year Ended December 31,
Hedges Under ASC 815
  Recognized in Income   2009   2008   2007
 
Commodity derivative contracts
    Derivative fair value loss (gain )   $ 47,462     $ (97,252 )   $ 26,301  
 
The following tables summarize the effect of derivative instruments designated as hedges under ASC 815 on the Consolidated Statements of Operations for the periods indicated (in thousands):
 
                         
    Amount of Loss Recognized
    in Accumulated OCI
    (Effective Portion)
Derivatives Designated as
  Year Ended December 31,
Hedges Under ASC 815
  2009   2008   2007
 
Interest rate swaps
  $ 2,946     $ 4,505     $  
 
                         
    Amount of Loss Reclassified
    from Accumulated
    OCI into Income
    (Effective Portion)
Location of Loss Reclassified from Accumulated
  Year Ended December 31,
OCI into Income (Effective Portion)
  2009   2008   2007
 
Interest expense
  $ 3,785     $ 246     $  
 


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ENCORE ENERGY PARTNERS LP
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
                         
    Amount of Loss Recognized
    in Income as Ineffective
    Year Ended December 31,
Location of Loss Recognized in Income as Ineffective
  2009   2008   2007
 
Derivative fair value loss (gain)
  $ 2     $ 372     $  
 
Fair Value Hierarchy
 
ASC 820-10 established a fair value hierarchy that prioritizes the inputs used to measure fair value. The three levels of the fair value hierarchy defined by ASC 820-10 are as follows:
 
  •  Level 1 — Unadjusted quoted prices are available in active markets for identical assets or liabilities.
 
  •  Level 2 — Pricing inputs, other than quoted prices within Level 1, that are either directly or indirectly observable.
 
  •  Level 3 — Pricing inputs that are unobservable requiring the use of valuation methodologies that result in management’s best estimate of fair value.
 
ENP’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the financial assets and liabilities and their placement within the fair value hierarchy levels. The following methods and assumptions were used to estimate the fair values of ENP’s assets and liabilities that are accounted for at fair value on a recurring basis:
 
  •  Level 2 — Fair values of oil and natural gas swaps were estimated using a combined income-based and market-based valuation methodology based upon forward commodity price curves obtained from independent pricing services reflecting broker market quotes. Fair values of interest rate swaps were estimated using a combined income-based and market-based valuation methodology based upon credit ratings and forward interest rate yield curves obtained from independent pricing services reflecting broker market quotes.
 
  •  Level 3 — ENP’s oil and natural gas calls, puts, and short puts are average value options, which are not exchange-traded contracts. Settlement is determined by the average underlying price over a predetermined period of time. ENP uses both observable and unobservable inputs in a Black-Scholes valuation model to determine fair value. Accordingly, these derivative instruments are classified within the Level 3 valuation hierarchy. The observable inputs of ENP’s valuation model include: (1) current market and contractual prices for the underlying instruments; (2) quoted forward prices for oil and natural gas; and (3) interest rates, such as a LIBOR curve for a term similar to the commodity derivative contract. The unobservable input of ENP’s valuation model is volatility. The implied volatilities for ENP’s calls, puts, and short puts with comparable strike prices are based on the settlement values from certain exchange-traded contracts. The implied volatilities for calls, puts, and short puts where there are no exchange-traded contracts with the same strike price are extrapolated from exchange-traded implied volatilities by an independent party.
 
ENP adjusts the valuations from the valuation model for nonperformance risk, using management’s estimate of the counterparty’s credit quality for asset positions and ENP’s credit quality for liability positions. ENP uses multiple sources of third-party credit data in determining counterparty nonperformance risk, including credit default swaps. ENP considers the impact of netting and offset provisions in the agreements on counterparty credit risk, including whether the position with the counterparty is a net asset or net liability. There were no changes in the valuation techniques used to measure the fair value of ENP’s oil and natural gas calls, puts, or short puts during 2009.

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ENCORE ENERGY PARTNERS LP
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
The following table sets forth ENP’s assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2009:
 
                                 
          Fair Value Measurements at Reporting Date Using  
          Quoted Prices in
          Significant
 
    Asset (Liability) at
    Active Markets for
    Significant Other
    Unobservable
 
    December 31,
    Identical Assets
    Observable Inputs
    Inputs
 
Description
  2009     (Level 1)     (Level 2)     (Level 3)  
    (In thousands)  
 
Oil derivative contracts — swaps
  $ (12,443 )   $     $ (12,443 )   $  
Oil derivative contracts — floors and caps
    8,585                   8,585  
Natural gas derivative contracts — swaps
    2,087             2,087        
Natural gas derivative contracts — floors and caps
    8,528                   8,528  
Interest rate swaps
    (3,669 )           (3,669 )      
                                 
Total
  $ 3,088     $     $ (14,025 )   $ 17,113  
                                 
 
The following table summarizes the changes in the fair value of ENP’s Level 3 assets and liabilities for 2009:
 
                         
    Fair Value Measurements Using Significant
 
    Unobservable Inputs (Level 3)  
          Natural Gas
       
    Oil Derivative
    Derivative
       
    Contracts — Floors
    Contracts — Floors
       
    and Caps     and Caps     Total  
    (In thousands)  
 
Balance at January 1, 2009
  $ 95,430     $ 12,741     $ 108,171  
Total gains (losses):
                       
Included in earnings
    (32,249 )     8,940       (23,309 )
Settlements
    (54,596 )     (13,153 )     (67,749 )
                         
Balance at December 31, 2009
  $ 8,585     $ 8,528     $ 17,113  
                         
The amount of total gains or losses for the period included in earnings attributable to the change in unrealized gains or losses relating to assets still held at the reporting date
  $ (32,249 )   $ 8,940     $ (23,309 )
                         
 
Since ENP does not use hedge accounting for its commodity derivative contracts, all gains and losses on its Level 3 assets and liabilities are included in “Derivative fair value loss (gain)” in the accompanying Consolidated Statements of Operations.
 
All fair values have been adjusted for nonperformance risk resulting in a reduction of the net commodity derivative asset of approximately $0.1 million as of December 31, 2009. For commodity derivative contracts which are in an asset position, ENP uses the counterparty’s credit default swap rating. For commodity derivative contracts which are in a liability position, ENP uses the average credit default swap rating of its peer companies as ENP does not have its own credit default swap rating.
 
ENP’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the nonfinancial assets and liabilities and their placement within the


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ENCORE ENERGY PARTNERS LP
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
fair value hierarchy levels. The following methods and assumptions were used to estimate the fair values of ENP’s assets and liabilities that are accounted for at fair value on a nonrecurring basis:
 
  •  Level 3 — Fair values of asset retirement obligations are determined using discounted cash flow methodologies based on inputs, such as plugging costs and reserve lives, which are not readily available in public markets. Please read “Note 5. Asset Retirement Obligations” for additional discussion of ENP’s asset retirement obligations.
 
The following table sets forth ENP’s assets and liabilities that were accounted for at fair value on a nonrecurring basis as of December 31, 2009:
 
                                         
        Fair Value Measurements Using    
        Quoted Prices in
           
    Liability at
  Active Markets for
  Significant Other
  Significant
   
    December 31,
  Identical Assets
  Observable Inputs
  Unobservable Inputs
  Total Gains
Description
  2009   (Level 1)   (Level 2)   (Level 3)   (Losses)
    (In thousands)
 
Asset retirement obligations
  $ 89     $     $     $ 89     $  
 
Note 11.   Related Party Transactions
 
Administrative Services Agreement
 
ENP does not have any employees. The employees supporting ENP’s operations are employees of EAC. As discussed in “Note 1. Formation of the Partnership and Description of Business,” ENP entered into the Administrative Services Agreement pursuant to which Encore Operating performs administrative services for ENP, such as accounting, corporate development, finance, land, legal, and engineering. In addition, Encore Operating provides all personnel, facilities, goods, and equipment necessary to perform these services which are not otherwise provided for by ENP. Encore Operating is not liable to ENP 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.
 
Encore Operating initially received an administrative fee of $1.75 per BOE of ENP’s production for such services. From April 1, 2008 to March 31, 2009, the administration fee was $1.88 per BOE of ENP’s production. Effective April 1, 2009, the administrative fee increased to $2.02 per BOE of ENP’s production. ENP also reimburses Encore Operating for actual third-party expenses incurred on ENP’s behalf. Encore Operating has substantial discretion in determining which third-party expenses to incur on ENP’s behalf. In addition, Encore Operating 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.
 
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 ENP acquires additional assets, Encore Operating 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 the General Partner upon the recommendation of its conflicts committee; and
 
  •  otherwise as agreed upon by Encore Operating and the General Partner, with the approval of the conflicts committee of the board of directors of the General Partner.
 
ENP reimburses EAC for any state income, franchise, or similar tax incurred by EAC resulting from the inclusion of ENP in consolidated tax returns with EAC as required by applicable law. The amount of any such


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ENCORE ENERGY PARTNERS LP
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
reimbursement is limited to the tax that ENP would have incurred had it not been included in a combined group with EAC.
 
Administrative fees (including COPAS recovery) paid to Encore Operating pursuant to the Administrative Services Agreement are included in “General and administrative expenses” in the accompanying Consolidated Statement of Operations. The reimbursements of actual third-party expenses incurred by Encore Operating on ENP’s behalf are included in “Lease operating expense” in the accompanying Consolidated Statement of Operations. The following table shows amounts paid by ENP to Encore Operating pursuant to the Administrative Services Agreement for the periods indicated:
 
                         
    Year Ended December 31,
    2009   2008   2007
    (In thousands)
 
Administrative fees (including COPAS recovery)
  $ 5,693     $ 6,600     $ 2,848  
Third-party expenses
    5,352       8,269       3,502  
 
As of December 31, 2009 and 2008, ENP had a payable to EAC of $2.8 million and $5.5 million, respectively, which is reflected as “Accounts payable — affiliate” in the accompanying Consolidated Balance Sheets and a receivable from EAC of $8.2 million and $3.9 million, respectively, which is reflected as “Accounts receivable — affiliate” in the accompanying Consolidated Balance Sheets.
 
Acquisitions from EAC
 
As previously discussed, ENP acquired (1) the Permian and Williston Basin Assets from Encore Operating in February 2008 for approximately $125.0 million in cash and the issuance of 6,884,776 ENP common units to Encore Operating, (2) the Arkoma Basin Assets from Encore Operating in January 2009 for approximately $46.4 million in cash, (3) the Williston Basin Assets from Encore Operating in June 2009 for approximately $25.2 million in cash, and (4) the Rockies and Permian Basin Assets from Encore Operating in August 2009 for approximately $179.6 million in cash. Prior to acquisition by ENP, these properties were owned by EAC and were not separate legal entities.
 
In addition to payroll-related expenses, EAC incurred general and administrative expenses related to leasing office space and other corporate overhead expenses during the period these properties were owned by EAC. A portion of EAC’s consolidated general and administrative expenses were allocated to ENP and included in the accompanying Consolidated Statements of Operations based on the respective percentage of BOE produced by the properties in relation to the total BOE produced by EAC on a consolidated basis. A portion of EAC’s consolidated indirect lease operating overhead expenses were allocated to ENP included in the accompanying Consolidated Statements of Operations based on its share of EAC’s direct lease operating expense.
 
Distributions
 
During 2009, 2008, and 2007, ENP paid cash distributions of approximately $43.9 million, $46.9 million, and $0.8 million, respectively, to EAC and its subsidiaries, including the General Partner. During 2008 and 2007, ENP paid cash distributions of approximately $3.5 million and $27,000, respectively, to certain executive officers of the General Partner based on their ownership of management incentive units.
 
Other
 
As discussed in “Note 6. Long-Term Debt,” during 2007, ENP had a subordinated credit agreement with EAP Operating, which was repaid in full with a portion of the net proceeds from the IPO.
 
EAC contributed $93.7 million in cash to ENP in March 2007. These proceeds were used by ENP, along with proceeds from the borrowings under ENP’s long-term debt agreements, to purchase the Elk Basin Assets.


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ENCORE ENERGY PARTNERS LP
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Additionally, EAC made a non-cash contribution in March 2007 of derivative oil put contracts representing 2,500 Bbls/D of production at $65.00 per Bbl for the period of April 2007 through December 2008. At the date of transfer, the derivative contracts had a fair value of $9.4 million.
 
Note 12.   Subsequent Events
 
Subsequent events were evaluated through February 24, 2010, which is the date the financial statements were issued.
 
On January 25, 2010, ENP announced that the board of directors of the General Partner declared an ENP cash distribution for the fourth quarter of 2009 to unitholders of record as of the close of business on February 8, 2010 at a rate of $0.5375 per unit. Approximately $24.6 million was paid to unitholders on February 12, 2010.


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ENCORE ENERGY PARTNERS LP
 
SUPPLEMENTARY INFORMATION
 
Capitalized Costs and Costs Incurred Relating to Oil and Natural Gas Producing Activities
 
The capitalized cost of oil and natural gas properties was as follows as of the dates indicated:
 
                 
    December 31,  
    2009     2008  
    (In thousands)  
 
Properties and equipment, at cost — successful efforts method:
               
Proved properties, including wells and related equipment
  $ 851,833     $ 814,903  
Unproved properties
    55       84  
Accumulated depletion, depreciation, and amortization
    (210,417 )     (154,584 )
                 
    $ 641,471     $ 660,403  
                 
 
The following table summarizes costs incurred related to oil and natural gas properties for the periods indicated:
 
                         
    Year Ended December 31,  
    2009     2008     2007  
    (In thousands)  
 
Acquisitions:
                       
Proved properties(a)
  $ 32,265     $ 5,940     $ 498,057  
Unproved properties
    1             105  
                         
Total acquisitions
    32,266       5,940       498,162  
                         
Development:
                       
Drilling and exploitation(b)
    7,197       31,450       21,277  
                         
Total development
    7,197       31,450       21,277  
                         
Exploration:
                       
Drilling and exploitation
    1,088       8,104       9,899  
Other
    135       119       101  
                         
Total exploration
    1,223       8,223       10,000  
                         
Total costs incurred
  $ 40,686     $ 45,613     $ 529,439  
                         
 
 
(a) Includes asset retirement obligations incurred for acquisition activities of $66 thousand and $6.5 million in 2009 and 2007, respectively.
 
(b) Includes asset retirement obligations incurred for development activities of $23 thousand, $29 thousand, and $0.1 million during 2009, 2008, and 2007, respectively.
 
Oil & Natural Gas Producing Activities — Unaudited
 
The estimates of ENP’s proved oil and natural gas reserves, which are located entirely within the United States, were prepared in accordance with guidelines established by the SEC. Proved oil and natural gas reserve quantities are derived from estimates prepared by Miller and Lents, Ltd., who are independent petroleum engineers.
 
Future prices received for production and future production costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. There can be no assurance that the proved reserves will be developed within the periods assumed or that prices and costs will remain constant. Actual production may not equal the estimated amounts used in the preparation of reserve projections. In accordance


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ENCORE ENERGY PARTNERS LP
 
 
SUPPLEMENTARY INFORMATION — (Continued)
 
with SEC guidelines, 2009 estimates of future net cash flows from ENP’s properties and the representative value thereof are made using an unweighted average of the closing oil and natural gas prices for the applicable commodity on the first day of each month in 2009 and are held constant throughout the life of the properties. In accordance with past SEC guidelines, 2008 and 2007 estimates of future net cash flows from ENP’s properties and the representative value thereof are made using oil and natural gas prices in effect as of the dates of such estimates and are held constant throughout the life of the properties. Prices used in estimating ENP’s future net cash flows were as follows:
 
                         
    2009   2008   2007
 
Oil (per Bbl)
  $ 61.18     $ 44.60     $ 96.01  
Natural gas (per Mcf)
  $ 3.83     $ 5.62     $ 7.47  
 
Net future cash inflows have not been adjusted for commodity derivative contracts outstanding at the end of the year. Future cash inflows are reduced by estimated production and development costs, which are based on year-end economic conditions and held constant throughout the life of the properties, by estimated abandonment costs, net of salvage, and by the estimated effect of future income taxes due to the Texas margin tax. Future federal income taxes have not been deducted from future net revenues in the calculation of ENP’s standardized measure as each partner is separately taxed on his share of ENP’s taxable income.
 
There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures. 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 are often materially different from the quantities of oil and natural gas that are ultimately recovered. Reserve estimates are integral to management’s analysis of impairments of oil and natural gas properties and the calculation of DD&A on these properties.
 
ENP’s estimated net quantities of proved oil and natural gas reserves were as follows as of the dates indicated:
 
                         
    December 31,  
    2009     2008     2007  
 
Proved developed reserves:
                       
Oil (MBbls)
    26,341       24,769       30,851  
Natural gas (MMcf)
    78,379       70,462       72,955  
Combined (MBOE)
    39,404       36,513       43,010  
Proved undeveloped reserves:
                       
Oil (MBbls)
    2,589       2,509       4,377  
Natural gas (MMcf)
    6,320       7,549       10,283  
Combined (MBOE)
    3,643       3,767       6,091  
Proved reserves:
                       
Oil (MBbls)
    28,930       27,278       35,228  
Natural gas (MMcf)
    84,699       78,011       83,238  
Combined (MBOE)
    43,047       40,280       49,101  


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ENCORE ENERGY PARTNERS LP
 
 
SUPPLEMENTARY INFORMATION — (Continued)
 
The changes in ENP’s proved reserves were as follows for the periods indicated:
 
                         
          Natural
    Oil
 
    Oil
    Gas
    Equivalent
 
    (MBbls)     (MMcf)     (MBOE)  
 
Balance, December 31, 2006(a)
    9,073       76,824       21,877  
Purchases of minerals-in-place
    25,965       6,221       27,002  
Extensions and discoveries
    488       7,414       1,724  
Revisions of previous estimates
    1,934       (1,470 )     1,688  
Production
    (2,232 )     (5,751 )     (3,190 )
                         
Balance, December 31, 2007(a)
    35,228       83,238       49,101  
Purchases of minerals-in-place
    32       2,489       447  
Extensions and discoveries
    148       2,832       620  
Revisions of previous estimates
    (5,596 )     (4,329 )     (6,318 )
Production
    (2,534 )     (6,219 )     (3,570 )
                         
Balance, December 31, 2008(a)
    27,278       78,011       40,280  
Purchases of minerals-in-place
          18,837       3,140  
Extensions and discoveries
    2       1,112       187  
Revisions of previous estimates
    3,987       (7,164 )     2,793  
Production
    (2,337 )     (6,097 )     (3,353 )
                         
Balance, December 31, 2009
    28,930       84,699       43,047  
                         
 
 
(a) Includes 1,585 MBOE, 1,510 MBOE, and 1,952 MBOE of proved reserves as of December 31, 2008, 2007, and 2006, respectively, associated with the Arkoma Basin Assets ENP acquired from Encore Operating in January 2009. Also includes 1,899 MBOE, 2,330 MBOE, and 444 MBOE of proved reserves as of December 31, 2008, 2007, and 2006, respectively, associated with the Williston Basin Assets ENP acquired from Encore Operating in June 2009. Also includes 10,732 MBOE, 13,663 MBOE, and 6,321 MBOE of proved reserves as of December 31, 2008, 2007, and 2006, respectively, associated with the Rockies and Permian Basin Assets ENP acquired from Encore Operating in August 2009. The acquisitions of these assets were accounted for as transactions between entities under common control, similar to a pooling of interests, whereby ENP’s historical financial information and proved reserve volumes were recast to include the acquired properties for all periods the properties were owned by Encore Operating.
 
Recent 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. Application of the new reserve rules resulted in the use of lower prices at December 31, 2009 for both oil and natural gas than would have resulted under the previous rules. Use of new 12-month average pricing rules at December 31, 2009 resulted in a decrease in proved reserves of approximately 2.2 MMBOE. Pursuant to the SEC’s final rule, prior period reserves were not restated.


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ENCORE ENERGY PARTNERS LP
 
 
SUPPLEMENTARY INFORMATION — (Continued)
 
 
ENP’s standardized measure of discounted estimated future net cash flows was as follows as of the dates indicated:
 
                         
    December 31,  
    2009     2008     2007  
    (In thousands)  
 
Future cash inflows
  $ 1,879,504     $ 1,406,100     $ 3,392,199  
Future production costs
    (819,352 )     (706,589 )     (1,157,893 )
Future development costs
    (46,852 )     (50,540 )     (61,961 )
Future abandonment costs, net of salvage
    (29,339 )     (28,771 )     (27,750 )
Future income tax expense
    (1,217 )     (182 )     (7,344 )
                         
Future net cash flows
    982,744       620,018       2,137,251  
10% annual discount
    (488,243 )     (293,396 )     (1,073,527 )
                         
Standardized measure of discounted estimated future net cash flows
  $ 494,501     $ 326,622     $ 1,063,724  
                         
 
The changes in ENP’s standardized measure of discounted estimated future net cash flows were as follows for the periods indicated:
 
                         
    Year Ended December 31,  
    2009     2008     2007  
    (In thousands)  
 
Net change in prices and production costs
  $ 153,083     $ (660,592 )   $ 145,074  
Purchases of minerals-in-place
    19,136       5,856       719,376  
Extensions, discoveries, and improved recovery
    1,588       5,938       28,692  
Revisions of previous quantity estimates
    65,300       (60,036 )     46,995  
Production, net of production costs
    (95,270 )     (76,970 )     (161,737 )
Previously estimated development costs incurred during the period
    4,732       13,685       17,542  
Accretion of discount
    32,662       106,373       25,527  
Change in estimated future development costs
    (3,527 )     (6,372 )     (39,806 )
Net change in income taxes
    (457 )     3,345       (2,427 )
Change in timing and other
    (9,368 )     (68,329 )     29,225  
                         
Net change in standardized measure
    167,879       (737,102 )     808,461  
Standardized measure, beginning of year
    326,622       1,063,724       255,263  
                         
Standardized measure, end of year
  $ 494,501     $ 326,622     $ 1,063,724  
                         


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ENCORE ENERGY PARTNERS LP
 
 
SUPPLEMENTARY INFORMATION — (Continued)
 
Selected Quarterly Financial Data — Unaudited
 
The following table provides selected quarterly financial data for the periods indicated:
 
                                 
    Quarter  
    First     Second     Third     Fourth  
    (In thousands, except per unit data)  
 
2009
                               
                                 
Revenues, as reported
  $ 18,651     $ 27,246     $ 41,032     $ 46,560  
Plus: revenues from assets acquired from affiliate
    7,648       9,380              
                                 
Revenues, as recast
  $ 26,299     $ 36,626     $ 41,032     $ 46,560  
                                 
Operating income (loss), as reported
  $ 6,780     $ (35,043 )   $ 10,383     $ (10,059 )
Plus: operating income (loss) from assets acquired from affiliate
    (2,492 )     1,044              
                                 
Operating income (loss), as recast
  $ 4,288     $ (33,999 )   $ 10,383     $ (10,059 )
                                 
Net income (loss), as reported
  $ 4,568     $ (37,593 )   $ 7,460     $ (13,316 )
Plus: net income (loss) from assets acquired from affiliate
    (2,492 )     1,044              
                                 
Net income (loss), as recast
  $ 2,076     $ (36,549 )   $ 7,460     $ (13,316 )
                                 
Net income (loss) allocation:
                               
Limited partners’ interest in net income (loss)
  $ 4,499     $ (37,093 )   $ 5,904     $ (13,169 )
General partner’s interest in net income (loss)
  $ 69     $ (630 )   $ 63     $ (147 )
Net income (loss) per common unit:
                               
Basic
  $ 0.14     $ (1.08 )   $ 0.13     $ (0.29 )
Diluted
  $ 0.14     $ (1.08 )   $ 0.13     $ (0.29 )
2008
                               
                                 
Revenues, as reported
  $ 49,245     $ 67,160     $ 84,110     $ 26,383  
Plus: revenues from assets acquired from affiliate
    23,377       24,312             11,294  
                                 
Revenues, as recast
  $ 72,622     $ 91,472     $ 84,110     $ 37,677  
                                 
Operating income (loss), as reported
  $ 7,291     $ (38,817 )   $ 113,981     $ 120,278  
Plus: operating income from assets acquired from affiliate
    11,464       13,810             381  
                                 
Operating income (loss)
  $ 18,755     $ (25,007 )   $ 113,981     $ 120,659  
                                 
Operating income (loss), as reported
  $ 5,585     $ (40,526 )   $ 111,892     $ 118,150  
Plus: operating income from assets acquired from affiliate
    11,550       13,810             295  
                                 
Net income (loss)
  $ 17,135     $ (26,716 )   $ 111,892     $ 118,445  
                                 
Net income (loss) allocation:
                               
Limited partners’ interest in net income (loss)
  $ (247 )   $ (45,441 )   $ 89,716     $ 115,332  
General partner’s interest in net income (loss)
  $ (36 )   $ (735 )   $ 1,444     $ 1,843  
Net income (loss) per common unit:
                               
Basic
  $ (0.01 )   $ (1.45 )   $ 2.86     $ 3.68  
Diluted
  $ (0.01 )   $ (1.45 )   $ 2.86     $ 3.49  
 
In June 2009, ENP acquired the Williston Basin Assets from Encore Operating. In August 2009, ENP acquired the Rockies and Permian Basin Assets from Encore Operating. Because these assets were acquired from an affiliate, the acquisitions were accounted for as transactions between entities under common control, similar to a pooling of interests, whereby the assets and liabilities of the acquired properties were recorded at Encore Operating’s carrying value and ENP’s historical financial information was recast to include the acquired properties for all periods in which the properties were owned by Encore Operating. Accordingly, the above selected quarterly financial data reflects the historical results of ENP combined with those of the Williston Basin Assets and the Rockies and Permian Basin Assets.


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ENCORE ENERGY PARTNERS LP
 
 
SUPPLEMENTARY INFORMATION — (Continued)
 
As discussed in “Note 2. Summary of Significant Accounting Policies” and “Note 8. Earnings Per Unit,” ENP adopted ASC 260-10 on January 1, 2009 and all periods have been restated to calculate earnings per unit in accordance therewith.


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ENCORE ENERGY PARTNERS LP
 
ITEM 9.   CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
 
None.
 
ITEM 9A.   CONTROLS AND PROCEDURES
 
Evaluation of Disclosure Controls and Procedures
 
In accordance with Exchange Act Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of our general partner’s management, including the Chief Executive Officer and Chief Financial Officer of our general partner, of the effectiveness of the design and operation of our disclosure controls and procedures. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer of our general partner concluded that our disclosure controls and procedures were effective as of December 31, 2009 to ensure that information required to be disclosed in the reports we file or submit under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms and that information required to be disclosed is accumulated and communicated to management, including the Chief Executive Officer and Chief Financial Officer of our general partner, to allow timely decisions regarding required disclosure.
 
Management’s Report on Internal Control Over Financial Reporting
 
Our general partner’s management is responsible for establishing and maintaining adequate internal control over financial reporting. Our internal control over financial reporting is a process designed under the supervision of our general partner’s Chief Executive Officer and Chief Financial Officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our financial statements for external purposes in accordance with GAAP.
 
As of December 31, 2009, our general partner’s management assessed the effectiveness of our internal control over financial reporting based on the criteria for effective internal control over financial reporting established in “Internal Control — Integrated Framework,” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on that assessment, our general partner’s management determined that we maintained effective internal control over financial reporting as of December 31, 2009, based on those criteria.
 
Ernst & Young LLP, the independent registered public accounting firm that audited our consolidated financial statements included in this Report, has issued an attestation report on the effectiveness of our internal control over financial reporting as of December 31, 2009. The report, which expresses an unqualified opinion on the effectiveness of our internal control over financial reporting as of December 31, 2009, is included below.


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ENCORE ENERGY PARTNERS LP
 
Report of Independent Registered Public Accounting Firm
 
To the Board of Directors of Encore Energy Partners GP LLC
and Unitholders of Encore Energy Partners LP:
 
We have audited Encore Energy Partners LP’s (the “Partnership”) internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Encore Energy Partners LP’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Partnership’s internal control over financial reporting based on our audit.
 
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
 
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
 
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
 
In our opinion, Encore Energy Partners LP maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, based on the COSO criteria.
 
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Encore Energy Partners LP as of December 31, 2009 and 2008, and the related consolidated statements of operations, partners’ equity and comprehensive income (loss), and cash flows for each of the three years in the period ended December 31, 2009 and our report dated February 24, 2010 expressed an unqualified opinion thereon.
 
/s/ Ernst & Young LLP
 
Fort Worth, Texas
February 24, 2010


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ENCORE ENERGY PARTNERS LP
 
Changes in Internal Control over Financial Reporting
 
There were no changes in our internal control over financial reporting during the fourth quarter of 2009 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
 
ITEM 9B.   OTHER INFORMATION
 
None.
 
PART III
 
ITEM 10.   DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
 
Our general partner manages our operations and activities. All executive officers of our general partner are employees of EAC and devote time as needed to conduct our business and affairs. Our general partner has a board of directors that oversees its management, operations, and activities. The board of directors and executive officers of our general partner make all strategic decisions on our behalf.
 
At the closing of our initial public offering, we entered into an administrative services agreement with Encore Operating and EAC pursuant to which Encore Operating performs administrative services for us. For more information regarding the administrative services agreement, please read “Item 13. Certain Relationships and Related Party Transactions, and Director Independence — Administrative Services Agreement.”
 
Our general partner is not elected by our unitholders nor subject to re-election on a regular basis. Unitholders are also not entitled to elect the directors of our general partner or directly or indirectly participate in our management or operation. As owner of our general partner, EAC has the ability to elect all the members of the board of directors of our general partner. Our general partner owes a fiduciary duty to our unitholders, although our partnership agreement limits such duties and restricts the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty. Our general partner will be liable, as general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made specifically nonrecourse to it.


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Directors and Executive Officers of Our General Partner
 
The following table sets forth certain information regarding the members of the board of directors and the executive officers of our general partner. Directors are elected for one-year terms by EAC. The directors of our general partner hold office until the earlier of their death, resignation, removal, or disqualification or until their successors have been elected and qualified. Officers of our general partner serve at the discretion of the board of directors of our general partner.
 
             
Name
  Age    
Position with Encore Energy Partners GP LLC
 
I. Jon Brumley
    70     Chairman of the Board
Jon S. Brumley
    39     Chief Executive Officer, President, and Director
Robert C. Reeves
    40     Senior Vice President, Chief Financial Officer, Treasurer, and Corporate Secretary
L. Ben Nivens
    49     Senior Vice President and Chief Operating Officer
John W. Arms
    42     Senior Vice President, Acquisitions
Kevin Treadway
    44     Senior Vice President, Land
Andrea Hunter
    35     Vice President, Controller, and Principal Accounting Officer
Thomas H. Olle
    55     Vice President, Strategic Solutions
Andy R. Lowe
    58     Vice President, Marketing
Arnold L. Chavkin
    58     Director
John E. Jackson
    51     Director
J. Luther King, Jr. 
    69     Director
Clayton E. Melton
    66     Director
George W. Passela
    64     Director
 
Executive Officers
 
I. Jon Brumley has been Chairman of the Board of our general partner since February 2007. Mr. Brumley has been Chairman of the Board of EAC since its inception in April 1998. He also served as Chief Executive Officer of EAC from its inception until December 2005 and President of EAC from its inception until August 2002. Beginning in August 1996, Mr. Brumley served as Chairman and Chief Executive Officer of MESA Petroleum (an independent oil and gas company) until MESA’s merger in August 1997 with Parker & Parsley to form Pioneer Natural Resources Company (an independent oil and gas company). He served as Chairman and Chief Executive Officer of Pioneer until joining EAC in 1998. Mr. Brumley received a Bachelor of Business Administration from the University of Texas and a Master of Business Administration from the University of Pennsylvania Wharton School of Business. He is the father of Jon S. Brumley.
 
Jon S. Brumley has been the Chief Executive Officer, President, and Director of our general partner since February 2007. Mr. Brumley has been Chief Executive Officer of EAC since January 2006, President of EAC since August 2002, and a director of EAC since November 2001. He also held the positions of Executive Vice President — Business Development and Corporate Secretary from EAC’s inception in April 1998 until August 2002 and was a director of EAC from April 1999 until May 2001. Prior to joining EAC, Mr. Brumley held the position of Manager of Commodity Risk and Commercial Projects for Pioneer Natural Resources Company. He was with Pioneer since its creation by the merger of MESA and Parker & Parsley in August 1997. Prior to August 1997, Mr. Brumley served as Director — Business Development for MESA. Mr. Brumley received a Bachelor of Business Administration in Marketing from the University of Texas. He is the son of I. Jon Brumley.


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Robert C. Reeves has been the Senior Vice President, Chief Financial Officer, and Treasurer of our general partner since February 2007 and Corporate Secretary since May 2008. Mr. Reeves has been the Senior Vice President, Chief Financial Officer, and Treasurer of EAC since November 2006 and Corporate Secretary of EAC since May 2008. From November 2006 until January 2007, Mr. Reeves also served as Corporate Secretary of EAC. Mr. Reeves served as Senior Vice President, Chief Accounting Officer, Controller, and Assistant Corporate Secretary of EAC from November 2005 until November 2006. He served as EAC’s Vice President, Controller, and Assistant Corporate Secretary from August 2000 until October 2005. He served as Assistant Controller of EAC from April 1999 until August 2000. Prior to joining EAC, Mr. Reeves served as Assistant Controller for Hugoton Energy Corporation. Mr. Reeves received his Bachelor of Science degree in Accounting from the University of Kansas. He is a Certified Public Accountant.
 
L. Ben Nivens has been the Senior Vice President and Chief Operating Officer of our general partner since February 2007. Mr. Nivens has been Senior Vice President and Chief Operating Officer of EAC since November 2006. From October 2005 until November 2006, Mr. Nivens served as Senior Vice President, Chief Financial Officer, Treasurer, and Corporate Secretary of EAC. Mr. Nivens served as EAC’s Vice President of Corporate Strategy and Treasurer from June 2005 until October 2005. From April 2002 to June 2005, Mr. Nivens served as engineering manager and in other engineering positions for EAC. Prior to joining EAC, he worked as a reservoir engineer for Prize Energy from 1999 to 2002. From 1990 to 1999, Mr. Nivens worked in the corporate planning group at Union Pacific Resources and also served as a reservoir engineer. In addition, he worked as a reservoir engineer for Compass Bank in 1999. Mr. Nivens received a Bachelor of Science in Petroleum Engineering from Texas Tech University and a Masters of Business Administration from Southern Methodist University.
 
John W. Arms has been the Senior Vice President — Acquisitions of our general partner and EAC since February 2007. Mr. Arms served as Vice President of Business Development of EAC from September 2001 until February 2007. From November 1998 until September 2001, Mr. Arms served as Manager of Acquisitions and in various other petroleum engineering positions for EAC. Prior to joining EAC in November 1998, Mr. Arms was a Senior Reservoir Engineer for Union Pacific Resources and an Engineer at XTO Energy, Inc. Mr. Arms received a Bachelor of Science in Petroleum Engineering from the Colorado School of Mines.
 
Kevin Treadway has been the Senior Vice President — Land of our general partner and EAC since February 2008. Mr. Treadway served as the Vice President — Land of our general partner from February 2007 to February 2008. Mr. Treadway served as the Vice President — Land of EAC from April 2003 to February 2008. From May 2000 to April 2003, Mr. Treadway held various positions of increasing responsibility in EAC’s land department. Prior to joining EAC in May 2000, Mr. Treadway served as a landman at Coho Resources. Mr. Treadway received a Bachelor of Science in Petroleum Land Management from the University of Southwestern Louisiana.
 
Andrea Hunter has been the Vice President, Controller, and Principal Accounting Officer of our general partner and EAC since February 2008. From September 2007 to February 2008, Ms. Hunter served as Controller of our general partner and EAC since September 2007. From July 2003 to September 2007, Ms. Hunter held positions of increasing responsibility at EAC, including financial reporting senior manager. Prior to joining EAC in July 2003, Ms. Hunter worked in public accounting, first in the Assurance and Business Advisory Services of PricewaterhouseCoopers LLP and later as an editor at Thomson Publishing’s Practitioners Publishing Company. Ms. Hunter received a Master of Science and Bachelor of Business Administration, both in Accounting, from the University of Texas at Arlington. She is a Certified Public Accountant.
 
Thomas H. Olle has been the Vice President, Strategic Solutions of our general partner and EAC since February 2008. From February 2007 to February 2008, Mr. Olle served as Vice President, Mid-Continent Region of our general partner. From November 2006 to February 2008, Mr. Olle served as Vice President, Mid-Continent Region of EAC. From February 2005 until November 2006, Mr. Olle was EAC’s Senior Vice


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President, Asset Management. Mr. Olle served as EAC’s Senior Vice President, Asset Management of the Cedar Creek Anticline from April 2003 to February 2005. Mr. Olle joined EAC in March 2002 as Vice President of Engineering. Prior to joining EAC, Mr. Olle served as Senior Engineering Advisor of Burlington Resources, Inc. (an independent oil and gas company) from September 1999 to March 2002. From July 1986 to September 1999, he served as Regional Engineer of Burlington Resources. Mr. Olle received a Bachelor of Science degree with Highest Honors in Mechanical Engineering from the University of Texas at Austin.
 
Andy R. Lowe has been the Vice President, Marketing of our general partner since February 2008. Mr. Lowe has been the Vice President, Marketing of EAC since February 2007. From May 2006 until February 2007, Mr. Lowe was EAC’s Director of Marketing. Prior to joining EAC, Mr. Lowe was Vice President  — Marketing for Vintage Petroleum, Inc. from December 1997 until December 2005. Mr. Lowe served as General Manager — Marketing for Vintage Petroleum, Inc. from 1992 until December 1997. Mr. Lowe served as president of Quasar Energy, Inc. from 1990 until 1992, providing downstream natural gas marketing services. From September 1983 to November 1990, he was employed by Maxus Energy Corporation, formerly Diamond Shamrock Exploration Company, serving as Manager of Marketing and in various other management and supervisory capacities. From 1981 to September 1983, he was employed by American Quasar Exploration Company as Manager of Oil and Gas Marketing. From 1978 to 1981, Mr. Lowe was employed by Texas Pacific Oil Company serving in various positions in production and marketing. Mr. Lowe received a Bachelor of Science degree in Education from Texas Tech University.
 
Directors
 
I. Jon Brumley.  Please refer to page 123.
 
Jon S. Brumley.  Please refer to page 123.
 
Arnold L. Chavkin has been a director of our general partner since October 2007 and is the chairman of the audit committee of the board of directors of our general partner. Mr. Chavkin is also a member of the conflicts committee of the board of directors of our general partner. Mr. Chavkin is a managing director at Pinebrook Road Partners, a private equity fund. From 1991 until his retirement in 2006, he served in various capacities with JPMorgan Chase & Co, including as the Chief Investment Officer at J.P. Morgan Partners, LLC. Prior to that, Mr. Chavkin was a member of Chemical Bank’s merchant banking and corporate finance groups, specializing in mergers and acquisitions and private placements for the energy industry. Mr. Chavkin served as a director of EAC from 1998 to 2004. Mr. Chavkin is a Certified Public Accountant. He received a Bachelor of Arts degree and a Masters of Business Administration from Columbia University.
 
John E. Jackson has been a director of our general partner since February 2008. Mr. Jackson served as Chairman, Chief Executive Officer, and President of Price Gregory Services, Inc. (a pipeline-related infrastructure service provider in North America) from February 2008 until its sale on October 1, 2009. Mr. Jackson has served as a director of Exterran Holding, Inc. (formerly Hanover Compressor Company) since July 2004 and served as Hanover’s President and Chief Executive Officer from October 2004 to August 2007. Mr. Jackson joined Hanover in January 2002 as Senior Vice President and Chief Financial Officer. Mr. Jackson also serves as a director of Seitel, Inc.
 
J. Luther King, Jr. has been a director of our general partner since August 2007. Mr. King is the President of Luther King Capital Management Corporation, a registered investment advisory firm that he founded in 1979, and has served as President and Trustee of LKCM Funds, a registered investment company, since 1994. Mr. King serves as a director of Tyler Technologies, Inc. and is a member of its Audit Committee. In addition, Mr. King serves as the chairman of the board of trustees of Texas Christian University. Mr. King has a Bachelor of Science degree and a Masters of Business Administration from Texas Christian University and is a Chartered Financial Analyst.
 
Clayton E. Melton has been a director of our general partner since August 2007. Mr. Melton has served as the Vice President/General Manager of Gemaire, Texas a subsidiary of Gemaire Distributors L.L.C., a


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distributor of heating and air conditioning equipment located in Deerfield Beach, Florida, since October 1, 2009. From January 2003 to October 2009, he served as President of Atlantic Service & Supply LLC, a distributor of heating and air conditioning supplies. From May 1999 to December 2002, he served as President of Comfort Products L.L.C., an air conditioning and heating distribution company. Prior to May 1999, Mr. Melton held various leadership and management positions in his 34 years of service in the U.S. Army obtaining the rank of Brigadier General. Mr. Melton received a Bachelor of Science in Business Administration from William Carey College and a Masters of Public Administration from the University of Missouri.
 
George W. Passela has been a director of our general partner since August 2007. Mr. Passela is the Chief Financial Officer of Momentum Energy Group LLC, a natural gas gathering, compression, treating, and processing company. Prior to joining Momentum Energy, Mr. Passela was Managing Director at Banc of America Securities LLC, with responsibility for capital raising and investments in the exploration and production and midstream sectors. From 1977 until 2005, Mr. Passela was employed by The First National Bank of Boston in its International Division, initially working with multinational corporations that provided export and commodity financing in South America. From 1982 until 1987, he served as Branch Manager in Frankfurt, Germany. Upon returning to Boston, Mr. Passela established The First National Bank of Boston’s exploration and production practice and held various management positions in its energy group through 2005. Mr. Passela holds a Bachelor of Arts degree from the University of Miami and a Masters of Business Administration from the University of Utah.
 
Director Independence
 
The board of directors of our general partner has seven members, none of whom are officers or employees of EAC and its affiliates, including our general partner, other than Mr. I. Jon Brumley and Mr. Jon S. Brumley. The board of directors of our general partner has determined that Messrs. Chavkin, King, Melton, and Passela are independent, as defined for purposes of the listing standards of the NYSE. In making this determination, the board of directors of our general partner affirmatively determined that each independent director had no material relationship with EAC and its affiliates, including our general partner (either directly or as a partner, shareholder, or officer of an organization that has a relationship with EAC and its affiliates, including our general partner), and that none of the express disqualifications contained in the NYSE rules applied to any of them.
 
The board of directors of our general partner has adopted categorical standards to assist it in making independence determinations. However, the board of directors of our general partner considers all material relationships with each director in making its independence determinations. A relationship falls within the categorical standards if it:
 
  •  Is a type of relationship addressed in Item 404 of Regulation S-K under the Exchange Act or Section 303A.02(b) of the NYSE Listed Company Manual, but those rules neither require disclosure nor preclude a determination of independence; or
 
  •  Consists of charitable contributions by EAC and its affiliates, including our general partner, to an organization where a director is an executive officer and does not exceed the greater of $1 million or 2 percent of the organization’s gross revenue in any of the last three years.
 
None of the independent directors had relationships relevant to an independence determination that were outside the scope of the categorical standards.
 
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.


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Board Committees
 
As of February 17, 2010, the board of directors of our general partner had an audit committee and a conflicts committee. The following table sets forth the membership on each committee:
 
         
Name
  Audit   Conflicts
 
Arnold L. Chavkin
  Chair   Member
John E. Jackson
       
J. Luther King, Jr. 
  Member   Member
Clayton E. Melton
  Member   Member
George W. Passela
  Member   Chair
 
In 2009, the Audit Committee held 5 meetings, the Conflicts Committee held 4 meetings, and the board of directors of our general partner held 9 meetings. Each director attended at least 75 percent of all board and applicable committee meetings in 2009.
 
Audit Committee.  The Audit Committee’s purpose is, among other things, to assist the board of directors of our general partner in overseeing:
 
  •  the integrity of our financial statements;
 
  •  our compliance with legal and regulatory requirements;
 
  •  the independence, qualifications, and performance of our independent registered public accounting firm; and
 
  •  the performance of our internal audit function.
 
The board of directors of our general partner has determined that all members of the Audit Committee are independent under the listing standards of the NYSE and the rules of the SEC. In addition, the board of directors of our general partner has determined that Mr. Chavkin is an “audit committee financial expert” as defined in Item 407(d)(5) of Regulation S-K.
 
The charter of the Audit Committee is available free of charge on the “Corporate Governance” section of our website at www.encoreenp.com.
 
Conflicts Committee.  The Conflicts Committee reviews specific matters that the board of directors of our general partner believes may involve conflicts of interest. At the request of the board of directors of our general partner, the Conflicts Committee determines if the resolution of the conflict of interest is fair and reasonable to us. The members of the Conflicts Committee may not be officers or employees of our general partner or directors, officers, or employees of its affiliates, including EAC, and must meet the independence and experience standards established by the NYSE Listed Company Manual and the Securities Exchange Act of 1934 to serve on an audit committee of a board of directors, and certain other requirements. Any matters approved by the Conflicts Committee in good faith will be conclusively deemed to be fair and reasonable to us, approved by all of our partners and not a breach of our general partner of any duties it may owe us or our unitholders.
 
The board of directors of our general partner has determined that all members of the Conflicts Committee are independent under the listing standards of the NYSE.
 
Code of Business Conduct and Ethics and Governance Guidelines
 
We have adopted a Code of Business Conduct and Ethics for our general partner’s directors, officers (including our general partner’s principal executive officer, principal financial officer, and principal accounting officer), and employees. We have also adopted Governance Guidelines, which, in conjunction with our certificate of limited partnership, bylaws, and committee charters of the board of directors of our general partner, form the framework for our governance. We will post on our website any amendments to the Code of


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Business Conduct and Ethics or waivers of the Code of Business Conduct and Ethics for directors and executive officers of our general partner.
 
Our Code of Business Conduct and Ethics and the Governance Guidelines are available free of charge on the “Corporate Governance” section of our website at www.encoreenp.com.
 
Executive Sessions of Non-Management Directors
 
Messrs. Chavkin, Jackson, King, Melton, and Passela are non-management directors of our general partner and Messrs. Chavkin, King, Melton, and Passela are independent under the listing standards of the NYSE. The non-management directors meet in executive session without management participation at least three times per year. The purpose of these executive sessions is to promote open and candid discussion among the non-management directors. These meetings are chaired by the chairman of the Audit Committee.
 
Unitholder Communications
 
Individuals may communicate with the entire board of directors of our general partner or with our general partner’s non-management directors. Any such communication should be sent via letter addressed to the member or members of the board of directors of our general partner to whom the communication is directed. All such communications, other than unsolicited commercial solicitations or communications, will be forwarded to the appropriate director or directors for review.
 
Section 16(a) Beneficial Ownership Reporting Compliance
 
Section 16(a) of the Exchange Act requires directors and executive officers of our general partner and holders of more than 10 percent of our common units to file reports with the SEC regarding their ownership and changes in ownership of our securities. We believe that, during 2009, the directors and executive officers of our general partner and our 10 percent unitholders complied with all Section 16(a) filing requirements. In making these statements, we have relied upon examination of the copies of Forms 3, 4, and 5, and amendments thereto, provided to us and the written representations of the directors and executive officers of our general partner.
 
ITEM 11.   EXECUTIVE COMPENSATION
 
Compensation Discussion and Analysis
 
We do not employ any of the persons responsible for managing our business, and we do not have a compensation committee. Our general partner manages our operations and activities and its board of directors and officers make decisions on our behalf. All of the executive officers of our general partner serve in the same capacities for EAC. The compensation of EAC’s employees that perform services on our behalf (other than the long-term incentive plan benefits described below) are set by the compensation committee of, and paid for by, EAC. We do not expect to pay any salaries or bonuses, or to make awards under our long-term incentive plan, to the named executive officers of our general partner.


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Compensation Committee Report
 
Neither we nor our general partner has a compensation committee. The board of directors of our general partner has reviewed and discussed the Compensation Discussion and Analysis set forth above with management and based on this review and discussion has approved it for inclusion in this Form 10-K.
 
The board of directors of Encore Energy
Partners GP LLC:
I. Jon Brumley, Jon S. Brumley, Arnold L.
Chavkin, John E. Jackson, J. Luther King, Jr.,
Clayton E. Melton, and George W. Passela
 
Summary Compensation Table
 
The following table summarizes the total compensation awarded to, earned by, or paid to our general partner’s named executive officers for the periods indicated:
 
                                                                         
                            Change in Pension
       
                            Value and
       
                            Nonqualified
       
                Stock
      Non-Equity
  Deferred
       
            Cash
  Awards
  Option
  Incentive Plan
  Compensation
  All Other
   
Name and Title
  Year   Salary   Bonus   (a)   Awards   Compensation   Earnings   Compensation   Total
 
I. Jon Brumley
    2009     $     $     $     $     $     $     $     $  
Chairman of the Board
    2008                   1,236,785                               1,236,785  
      2007                   1,769,074                               1,769,074  
Jon S. Brumley
    2009                                                  
Chief Executive Officer
    2008                   1,236,785                               1,236,785  
and President
    2007                   1,769,074                               1,769,074  
Robert C. Reeves
    2009                                                  
Senior Vice President,
    2008                   951,373                               951,373  
Chief Financial Officer,
    2007                   1,360,825                               1,360,825  
Treasurer, and Corporate Secretary
                                                                       
L. Ben Nivens
    2009                                                  
Senior Vice President
    2008                   665,961                               665,961  
and Chief Operating
    2007                   952,578                               952,578  
Officer
                                                                       
John W. Arms
    2009                                                  
Senior Vice President,
    2008                   665,961                               665,961  
Acquisitions
    2007                   952,578                               952,578  
 
 
(a) Reflects the compensation cost recognized by us with respect to grants of management incentive units, which does not correspond to the actual value that may be realized by the named executive officers. Pursuant to SEC rules, the amounts shown exclude the impact of estimated forfeitures related to service-based vesting conditions.
 
Grants of Plan-Based Awards for 2009
 
Our general partner’s named executive officers did not receive any grants of plan — based awards with respect to performance in 2009.
 
Outstanding Equity Awards at December 31, 2009
 
At December 31, 2009, none of the named executive officers of our general partner held any outstanding equity awards in us. All previously issued management incentive units were converted into our common units in the fourth quarter of 2008.


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Units Vested
 
There were no vestings of plan-based awards for our general partner’s named executive officers during 2009.
 
Pension Benefits
 
We do not maintain any plans that provide for payments or other benefits at, following, or in connection with retirement.
 
Non-Qualified Deferred Compensation
 
We do not maintain any defined contribution or other plan that provides for the deferral of compensation on a basis that is not tax-qualified under the Code.
 
Potential Payments Upon Termination or Change-in-Control
 
None of our named executive officers were entitled to potential payments from us upon termination or a change-in-control as of December 31, 2009.
 
Compensation Committee Interlocks and Insider Participation
 
As previously discussed, our general partner’s board of directors is not required to maintain, and does not maintain, a compensation committee. I. Jon Brumley, our general partner’s chairman of the board of directors, serves as the chairman of the board of directors of EAC, and Jon S. Brumley, our general partner’s Chief Executive Officer and President and member of our general partner’s board of directors, serves as the Chief Executive Officer and President and member of the board of directors of EAC. However, all compensation decisions with respect to each of these persons are made by EAC and, other than with respect to the previously issued management incentive units, none of these individuals receive any compensation directly from us or our general partner. Please read “Item 13. Certain Relationships and Related Transactions, and Director Independence” for information about relationships among us, our general partner, and EAC.
 
Director Compensation
 
Officers or employees of our general partner or its affiliates who also serve as directors do not receive additional compensation for their service as a director of our general partner. Each director is fully indemnified by us for actions associated with being a director to the extent permitted under Delaware law.
 
The following table sets forth a summary of the compensation paid to or earned by non-employee directors of our general partner during 2009:
 
                                                 
                Change in
       
                Pension Value and
       
                Nonqualified
       
    Fees Earned
      Non-Equity
  Deferred
       
    or Paid in
  Unit
  Incentive Plan
  Compensation
  All Other
   
Name
  Cash(a)   Awards(b)   Compensation   Earnings   Compensation   Total(c)
 
Arnold L. Chavkin
  $ 130,000     $ 90,650     $     $     $     $ 220,650  
John E. Jackson
    68,000       90,650                         158,650  
J. Luther King, Jr. 
    123,000       90,650                         213,650  
Clayton E. Melton
    121,000       90,650                         211,650  
George W. Passela
    133,000       90,650                         223,650  
 
 
(a) Directors receive an annual retainer of $50,000 plus additional fees of $2,000 for attendance at each board meeting and $1,000 for attendance at each committee meeting. The chair of each committee receives an additional annual fee of $10,000. Each member of the conflicts committee receives a fee of $25,000 each


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time we seek approval under our partnership agreement of a potential conflict of interest in connection with a drop-down transaction between us and EAC.
 
(b) Directors receive an annual grant of 5,000 phantom units under the Encore Energy Partners GP LLC Long-Term Incentive Plan. Amount is determined by multiplying the number of phantom units granted by $18.13, the closing price of our common units on the NYSE on October 26, 2009, which was the date of grant. Phantom units vest in four equal annual installments, subject to immediate vesting in the event of a change in control or termination of employment due to death or disability and to such other terms as are set forth in the award agreement. Each phantom unit is accompanied by a distribution equivalent right, which entitles the holder to receive cash equal to the amount of any cash distributions made by us with respect to a common unit during the period the right is outstanding.
 
(c) We also reimburse directors for out-of-pocket expenses attendant to membership on the board of directors of our general partner. These amounts are excluded from the above table.
 
Long-Term Incentive Plan
 
In September 2007, the board of directors of our general partner approved the Encore Energy Partners GP LLC Long-Term Incentive Plan (the “LTIP”), which provides for the granting of options, restricted units, phantom units, unit appreciation rights, distribution equivalent rights, other unit-based awards, and unit awards. All employees, consultants, and directors of EAC, our general partner, and any of their subsidiaries and affiliates who perform services for us are eligible to be granted awards under the LTIP. The total number of common units reserved for issuance pursuant to the LTIP is 1,150,000. The LTIP is administered by the board of directors of our general partner or a committee thereof, referred to as the plan administrator.
 
The plan administrator may terminate or amend the LTIP at any time with respect to any units for which a grant has not yet been made. The plan administrator also has the right to alter or amend the LTIP or any part of the LTIP from time to time, including increasing the number of units that may be granted subject to the requirements of the exchange upon which the common units are listed at that time. However, no change in any outstanding grant may be made that would materially reduce the rights or benefits of the participant without the consent of the participant. The LTIP will expire on the earliest of (1) the date the units are no longer available under the LTIP for grants, (2) termination of the LTIP by the plan administrator, or (3) the date 10 years following the date of adoption.
 
Restricted Units.  A restricted unit is a common unit that vests over a six-month period of time and during that time is subject to forfeiture. The plan administrator may make grants of restricted units containing such terms as it shall determine, including the period over which restricted units will vest. The plan administrator, in its discretion, may base its determination upon the achievement of specified financial or other performance objectives. Restricted units will be entitled to receive quarterly distributions during the vesting period.
 
Phantom Units.  A phantom unit entitles the grantee to receive a common unit upon the vesting of the phantom unit or, in the discretion of the plan administrator, cash equivalent to the value of a common unit. The plan administrator may make grants of phantom units under the plan containing such terms as the plan administrator shall determine, including the period over which phantom units granted will vest. The plan administrator, in its discretion, may base its determination upon the achievement of specified financial objectives.
 
Unit Options.  The LTIP permits the grant of options covering common units. The plan administrator may make grants containing such terms as the plan administrator shall determine. Unit options must have an exercise price that is not less than the fair market value of the common units on the date of grant. In general, unit options granted will become exercisable over a period determined by the plan administrator.
 
Unit Appreciation Rights.  The LTIP permits the grant of unit appreciation rights. A unit appreciation right is an award that, upon exercise, entitles the participant to receive the excess of the fair market value of a


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common unit on the exercise date over the exercise price established for the unit appreciation right. Such excess will be paid in cash or common units. The plan administrator may make grants of unit appreciation rights containing such terms as the plan administrator shall determine. Unit appreciation rights must have an exercise price that is not less than the fair market value of the common units on the date of grant. In general, unit appreciation rights granted will become exercisable over a period determined by the plan administrator.
 
Distribution Equivalent Rights.  The plan administrator may, in its discretion, grant distribution equivalent rights (“DERs”) as a stand-alone award or with respect to phantom unit awards or other awards under the LTIP. DERs entitle the participant to receive cash or additional awards equal to the amount of any cash distributions made by us with respect to a common unit during the period the right is outstanding. Payment of a DER issued in connection with another award may be subject to the same vesting terms as the award to which it relates or different vesting terms, in the discretion of the plan administrator.
 
Other Unit-Based Awards.  The LTIP permits the grant of other unit-based awards, which are awards that are based, in whole or in part, on the value or performance of a common unit. Upon vesting, the award may be paid in common units, cash, or a combination thereof, as provided in the grant agreement.
 
Unit Awards.  The LTIP permits the grant of common units that are not subject to vesting restrictions. Unit awards may be in lieu of or in addition to other compensation payable to the individual.
 
Change in Control; Termination of Service.  Awards under the LTIP will vest and/or become exercisable, as applicable, upon a “change in control” of us or our general partner or upon a “Change of Control” as defined in EAC’s 2000 Incentive Stock Plan, unless provided otherwise by the plan administrator. The consequences of the termination of a grantee’s employment, consulting arrangement, or membership on the board of directors will be determined by the plan administrator in the terms of the relevant award agreement.
 
A “change in control” of us or our general partner under the LTIP includes the occurrence of one or more of the following events:
 
  •  any person or group, other than EAC or its affiliates, becomes the beneficial owner of 50 percent or more of us or our general partner;
 
  •  approval by our limited partners of the complete liquidation of us;
 
  •  the sale or other disposition of all or substantially all of our assets, other than to our general partner or its affiliates;
 
  •  a transaction resulting in someone other than our general partner or one of its affiliates becoming our general partner; or
 
  •  a transaction resulting in our general partner ceasing to be an affiliate of EAC.
 
A “Change in Control” is defined in EAC’s 2000 Incentive Stock Plan as the occurrence of one or more of the following events:
 
  •  any person or group acquires beneficial ownership of 40 percent or more of EAC, other than through any acquisition (1) directly from EAC, (2) by EAC and its affiliates, (3) by any employee benefit plan sponsored or maintained by EAC or any corporation controlled by EAC, (4) by a corporation pursuant to a permitted transaction described in the third bullet below, or (5) by a person or group that owned on the adoption date of EAC’s 2000 Incentive Stock Plan more than 20 percent of EAC’s outstanding capital stock;
 
  •  EAC’s incumbent board members, as of the effective date of EAC’s 2000 Incentive Stock Plan, cease to constitute at least a majority of EAC’s board of directors, provided that, any subsequent director whose election or nomination was approved by a majority vote of the directors then comprising EAC’s incumbent board members will generally be considered an EAC incumbent board member;


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  •  approval by EAC’s stockholders of a reorganization, merger, share exchange, or consolidation, unless, in each case following the transaction, (1) all or substantially all of EAC’s beneficial owners immediately prior to such transaction beneficially own more than 60 percent of the corporation resulting from such transaction in substantially the same proportions as their ownership immediately prior to such transaction, (2) no person or group beneficially owns 40 percent or more of the corporation resulting from such transaction except to the extent that such person or group beneficially owned 40 percent or more of EAC prior to the transaction, and (3) at least a majority of the board members of the corporation resulting from such transaction where EAC incumbent board members at the time of the execution of the initial agreement, or of the action of EAC’s board of directors, providing for such transaction; or
 
  •  approval by EAC’s stockholders of a complete liquidation or dissolution of EAC or sale or other disposition of all or substantially all of EAC’s assets, other than to a corporation with respect to which, following such sale or other disposition, (1) more than 60 percent of such corporation is then beneficially owned by all or substantially all of the persons or groups who were the beneficial owners of EAC immediately prior to such sale or other disposition in substantially the same proportion as their ownership immediately prior to such sale or other disposition, (2) less than 40 percent of such corporation is then beneficially owned by any person or group, except to the extent that such person or group owned 40 percent or more of EAC prior to the sale or disposition, and (3) at least a majority of the board members of such corporation were EAC’s incumbent board members at the time of the execution of the initial agreement, or of the action of EAC’s board of directors, providing for such sale or other disposition or were elected, appointed, or nominated by EAC’s board of directors.
 
Source of Units.  Common units to be delivered pursuant to awards under the LTIP may be common units acquired by our general partner in the open market, from any other person, directly from us, or any combination of the foregoing. If we issue new common units upon the grant, vesting or payment of awards under the long-term incentive plan, the total number of common units outstanding will increase.
 
ITEM 12.   SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS
 
The following table sets forth the beneficial ownership of our common units as of February 17, 2010 by:
 
  •  each person known by us to beneficially own 5 percent or more of our outstanding common units;
 
  •  each member of the board of directors of our general partner;
 
  •  each named executive officer of our general partner; and
 
  •  all directors and executive officers of our general partner as a group.


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Unless otherwise noted, the persons named below have sole voting and investment power with respect to such units.
 
                 
    Common Units
   
Name and Address of Beneficial Owner
  Beneficially Owned   Percent of Class
 
5% Beneficial Owners
               
Encore Acquisition Company(a)
    20,924,055       46.1 %
777 Main Street, Suite 1400
Fort Worth, TX 76040
               
Encore Partners LP Holdings LLC(a)
    9,995,801       22.0 %
777 Main Street, Suite 1400
Fort Worth, TX 76040
               
Encore Operating, L.P.(a)
    10,928,254       24.1 %
777 Main Street, Suite 1400
Fort Worth, TX 76040
               
Directors and Named Executive Officers(b)
               
I. Jon Brumley(c)
    616,711       1.4 %
Jon S. Brumley
    456,415       1.0 %
Robert C. Reeves(d)
    347,588       *  
L. Ben Nivens
    242,862       *  
John W. Arms
    265,062       *  
Arnold L. Chavkin
    20,500       *  
John E. Jackson
    15,000       *  
J. Luther King, Jr.(e)
    133,750       *  
Clayton E. Melton
    18,400       *  
George W. Passela
    25,000       *  
All directors and executive officers as a group (14 persons)
    2,145,288       4.7 %
 
 
 * Less than 1%.
 
(a) EAC is the ultimate parent company of Encore Energy Partners LP Holdings LLC and Encore Operating and therefore, may be deemed to beneficially own the ENP common units held by Encore Partners LP Holdings LLC and Encore Operating.
 
(b) Includes unvested phantom units as of February 17, 2010 as follows: Mr. Chavkin (11,250), Mr. Jackson (11,250), Mr. King (11,250), Mr. Melton (11,250), and Mr. Passela (11,250), and all directors and executive officers as a group (56,250).
 
(c) Mr. Brumley is the sole officer, director, and shareholder of a corporation that is the sole general partner of a limited partnership that owns 596,317 common units. Accordingly, Mr. Brumley has sole voting and dispositive power with respect to the common units owned by the partnership. In addition, 573,156 of the common units identified above are pledged as security with respect to outstanding indebtedness of Mr. Brumley.
 
(d) Includes 346,541 common units which are pledged as security with respect to outstanding indebtedness of Mr. Reeves.
 
(e) Includes 60,500 common units held by clients of Luther King Capital Management Corporation (“LKCM”), a registered investment advisory firm controlled by Mr. King. Pursuant to investment management agreements with such clients, LKCM generally has voting and investment power over such common units. Mr. King disclaims beneficial ownership of such common units, except to the extent of his pecuniary interest therein.


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The following table sets forth, as of February 17, 2010, the number of shares of common stock of EAC owned by each of the named executive officers and directors of our general partner and all executive officers and directors of our general partner as a group.
 
                 
    Shares Beneficially
   
Name of Beneficial Owner(a)(b)
  Owned   Percent of Class
 
I. Jon Brumley(c)
    2,615,105       4.6 %
Jon S. Brumley
    1,087,115       1.9 %
Robert C. Reeves
    221,512       *  
John W. Arms
    152,442       *  
L. Ben Nivens
    122,528       *  
Arnold L. Chavkin
          *  
John E. Jackson
    400       *  
J. Luther King, Jr.(d)
    284,385       *  
Clayton E. Melton
          *  
George W. Passela
          *  
All executive officers and directors as a group (14 persons)
    4,831,989       8.5 %
 
 
 * Less than 1%.
 
(a) Includes options that are or become exercisable within 60 days of February 17, 2010 as follows: Mr. I. Jon Brumley (337,638), Mr. Jon S. Brumley (374,506), Mr. Reeves (105,182), Mr. Nivens (28,685), and Mr. Arms (64,034), and all executive officers and directors as a group (1,101,748) upon the exercise of stock options granted pursuant to EAC’s incentive stock plans.
 
(b) Includes unvested restricted stock as of February 17, 2010 as follows: Mr. I. Jon Brumley (81,552), Mr. Jon S. Brumley (143,227), Mr. Reeves (62,375), Mr. Nivens (66,715), and Mr. Arms (43,545), and all directors and executive officers as a group (486,000).
 
(c) Mr. Brumley is the sole officer, director, and shareholder of a corporation that is the sole general partner of two limited partnerships that own a total of 1,945,013 shares. Accordingly, Mr. Brumley has sole voting and dispositive power with respect to the shares owned by these partnerships.
 
(d) Represents shares of EAC held by clients of LKCM. Pursuant to investment management agreements with such clients, LKCM generally has voting and investment power over such shares. Mr. King disclaims beneficial ownership of such shares, except to the extent of his pecuniary interest therein.
 
The following table sets forth information about our common units that may be issued under the LTIP as of December 31, 2009:
 
                         
    (a)   (b)   (c)
            Number of
    Number of
      Securities Remaining
    Securities to
      Available for
    be Issued
  Weighted-Average Exercise
  Future Issuance
    Upon Exercise
  Price of
  Under Equity Compensation
    of Outstanding
  Outstanding Options,
  Plans (Excluding
    Options, Warrants
  Warrants and
  Securities
    and Rights(a)   Rights   Reflected in Column (a))
 
Equity compensation plans approved by unitholders
                1,075,000  
Equity compensation plans not approved by unitholders
                 
                         
Total
                1,075,000  
                         
 
 
(a) There are no outstanding warrants or equity rights awarded under the LTIP. Excludes 56,250 shares of unvested phantom units.


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For discussion of our unit-based compensation plans, please read “Item 11. Executive Compensation.”
 
ITEM 13.   CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
 
As of February 17, 2010, affiliates of our general partner, including directors and executive officers of our general partner, owned 22,950,393 common units representing approximately 50.7 of our outstanding common units. In addition, our general partner owned all 504,851 general partner units representing a 1.1 percent general partner interest in us.
 
Distributions and Payments to Our General Partner and Its Affiliates
 
The following table summarizes the distributions and payments to be made by us to our general partner and its affiliates in connection with the ongoing operation and upon liquidation of ENP. These distributions and payments were determined by and among affiliated entities.
 
Ongoing Operations of ENP
 
 
Distributions of available cash to our
general partner and its affiliates
We make cash distributions to our unitholders, including our general partner and its affiliates, as the holders of 20,924,055 common units and all 504,851 general partner units, in accordance with their ownership percentages.
 
Payments to our general partner and its affiliates Our partnership agreement requires us to reimburse our general partner for all actual direct and indirect expenses it incurs or actual payments it makes on our behalf and all other expenses allocable to us or otherwise incurred by our general partner in connection with operating our business. We do not expect to incur any additional fees or to make other payments to our general partner in connection with operating our business. Our administrative services agreement requires us to pay Encore Operating an administrative fee of $2.02 per BOE of our production for administrative services performed by us and reimburse Encore Operating for actual third-party expenses incurred on our behalf. For further information regarding the administrative services agreement, please read “Administrative Services Agreement” below.
 
Withdrawal or removal of our general partner If our general partner withdraws or is removed, its general partner interest will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests.
 
Upon Liquidation of ENP
 
 
Liquidation Upon our liquidation, our partners, including our general partner, will be entitled to receive liquidating distributions according to their respective capital account balances.


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Administrative Services Agreement
 
We nor our general partner have any employees. The employees supporting our operations are employees of EAC. At the closing of our IPO, we entered into the administrative services agreement with our general partner, OLLC, Encore Operating, and EAC pursuant to which Encore Operating performs administrative services for us, such as accounting, corporate development, finance, land, legal, and engineering. In addition, Encore Operating provides all personnel, facilities, goods, and equipment necessary to perform these services which are not otherwise provided for by us. Encore Operating is 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.
 
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. Effective April 1, 2009, the administrative fee increased to $2.02 per BOE of our production. We also reimburse Encore Operating for actual third-party expenses incurred on our behalf. Encore Operating has substantial discretion in determining which third-party expenses to incur on our behalf. In addition, Encore Operating 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.
 
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, Encore Operating 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; or
 
  •  otherwise as agreed upon by Encore Operating and our general partner, with the approval of the conflicts committee of the board of directors of our general partner.
 
The administrative services agreement will terminate in the following circumstances:
 
  •  at our discretion upon 90 days notice to Encore Operating;
 
  •  at the discretion of Encore Operating upon 90 days notice to us;
 
  •  upon a change in control of our general partner or Encore Operating by EAC or upon Encore Operating’s failure to pay an employee within 30 days of the date such employee’s payment is due, subject to certain limitations; or
 
  •  upon the bankruptcy, dissolution, liquidation, or winding up of Encore Operating.
 
We also reimburse EAC for any state income, franchise, or similar tax incurred by EAC resulting from the inclusion of us in consolidated tax returns with EAC as required by applicable law. The amount of any such reimbursement is limited to the tax that we would have incurred had we not been included in a combined group with EAC.
 
Policies and Procedures for Approval of Related Person Transactions
 
The board of directors of our general partner has adopted a policy with respect to related person transactions to document procedures pursuant to which such transactions are reviewed, approved, or ratified. The policy applies to any transaction in which:
 
  •  ENP is a participant;
 
  •  any related person has a direct or indirect material interest; and


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  •  the amount involved exceeds $120,000, but excludes any transaction that does not require disclosure under Item 404(a) of Regulation S-K.
 
Director Independence
 
All members of the board of directors of our general partner, other than Mr. I. Jon Brumley, Mr. Jon S. Brumley, and Mr. John E. Jackson, are independent as defined under the independence standards established by the NYSE. 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.
 
ITEM 14.   PRINCIPAL ACCOUNTANT FEES AND SERVICES
 
The Audit Committee of the board of directors of our general partner appointed Ernst & Young LLP as our independent registered public accounting firm for 2010.
 
Fees Incurred by Us for Services Provided by Ernst & Young LLP
 
The following table shows the fees paid or accrued by us for services provided by Ernst & Young LLP during the periods indicated:
 
                 
    2009     2008  
 
Audit fees(a)
  $ 1,038,847     $ 868,471  
Audit-related fees
           
Tax fees
           
All other fees
           
                 
Total
  $ 1,038,847     $ 868,471  
                 
 
 
(a) Represent fees for professional services provided in connection with: (1) the annual audit of our consolidated financial statements and our general partner’s consolidated balance sheets; (2) the annual audit of our internal control over financial reporting; (3) the review of our quarterly consolidated financial statements; and (4) audit services provided in connection with SEC filings, including comfort letters, consents, and comment letters.
 
Audit Committee’s Pre-Approval Policy and Procedures
 
The policy of our general partner’s Audit Committee is to pre-approve all audit and permissible non-audit services provided by the independent registered public accounting firm. These services may include audit services, audit-related services, tax services, and other services. Pre-approval is detailed as to the specific service or category of service and is subject to a specific approval. Our general partner’s Audit Committee requires our independent registered public accounting firm and management to report on the actual fees charged for each category of service at Audit Committee meetings throughout the year.
 
During the year, circumstances may arise when it may become necessary to engage our independent registered public accounting firm for additional services not contemplated in the original pre-approval. In those circumstances, our general partner’s Audit Committee of our general partner requires specific pre-approval before engaging our independent registered public accounting firm. Our general partner’s Audit Committee of our general partner has delegated pre-approval authority to its chairman for those instances when pre-approval is needed prior to a scheduled meeting. The chairman of the Audit Committee of our general partner must report on such approval at the next scheduled meeting.
 
All services provided by our independent registered public accounting firm were pre-approved.


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PART IV
 
ITEM 15.   EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
 
(a) The following documents are filed as a part of this Report:
 
1. Financial Statements:
 
         
    Page
 
    80  
    81  
    82  
    83  
    84  
    85  
 
2. Financial Statement Schedules:
 
All financial statement schedules have been omitted because they are not applicable or the required information is presented in the consolidated financial statements and related notes.
 
(b) Exhibits
 
             
Exhibit
       
No.
 
Description
   
 
  3 .1   Certificate of Limited Partnership of Encore Energy Partners LP (incorporated by reference from Exhibit 3.1 to ENP’s Registration Statement on Form S-1 (File No. 333-142847), filed with the SEC on May 11, 2007).    
  3 .2   Second Amended and Restated Agreement of Limited Partnership of Encore Energy Partners LP, dated as of September 17, 2007 (incorporated by reference from Exhibit 3.1 to ENP’s Current Report on Form 8-K, filed with the SEC on September 21, 2007).    
  3 .2.1   Amendment No. 1 to Second Amended and Restated Agreement of Limited Partnership of Encore Energy Partners LP, dated as of May 10, 2007 (incorporated by reference from Exhibit 3.1 to ENP’s Current Report on Form 8-K, filed with the SEC on April 18, 2008).    
  10 .1   Credit Agreement, dated as of March 7, 2007, by and among Encore Energy Partners Operating LLC, Encore Energy Partners LP, Bank of America, N.A., as administrative agent and L/C Issuer, Banc of America Securities LLC, as sole lead arranger and sole book manager, and other lenders (incorporated by reference from Exhibit 10.2 to EAC’s Current Report on Form 8-K, filed with the SEC on March 13, 2007).    
  10 .2   First Amendment to Credit Agreement, dated as of August 22, 2007, by and among Encore Energy Partners Operating LLC, Encore Energy Partner LP, Bank of America, N.A., as administrative agent and L/C Issuer, Banc of America Securities LLC, as sole lead arranger and sole book manager, and other lenders (incorporated by reference from Exhibit 10.2 to Amendment No. 4 to ENP’s Registration Statement on Form S-1, filed with the SEC on August 28, 2007).    
  10 .3   Second Amendment to Credit Agreement, dated as of March 10, 2009, by and among Encore Energy Partners Operating LLC, Encore Energy Partners LP, Bank of America, N.A., as administrative agent and L/C issuer, and the lenders party thereto (incorporated by reference to Exhibit 10.1 of ENP’s Current Report on Form 8-K, filed with the SEC on March 11, 2009).    


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Exhibit
       
No.
 
Description
   
 
  10 .4   Third Amendment to Credit Agreement, dated as of August 11, 2009, by and among Encore Energy Partners Operating LLC, Encore Energy Partners LP, Bank of America, N.A., as the administrative agent and L/C issuer, and the lenders party thereto (incorporated by reference from Exhibit 10.1 of ENP’s Current Report on Form 8-K filed on August 13, 2009).    
  10 .5   Fourth Amendment to Credit Agreement, dated as of November 24, 2009, by and among Encore Energy Partners Operating LLC, Encore Energy Partners LP, Bank of America, N.A., as the administrative agent and L/C issuer, and the lenders party thereto (incorporated by reference to Exhibit 10.1 of Encore Energy Partners LP’s Current Report on Form 8-K, filed with the SEC on December 1, 2009).    
  10 .6   Amended and Restated Administrative Services Agreement, dated as of September 17, 2007, by and among Encore Energy Partners GP LLC, Encore Energy Partners LP, Encore Energy Partners Operating LLC, Encore Acquisition Company and Encore Operating, L.P. (incorporated by reference from Exhibit 10.2 to ENP’s Current Report on Form 8-K, filed with the SEC on September 21, 2007).    
  10 .7+   Encore Energy Partners GP LLC Long-Term Incentive Plan, dated as of September 17, 2007 (incorporated by reference from Exhibit 10.3 to ENP’s Current Report on Form 8-K, filed with the SEC on September 21, 2007).    
  10 .8+   Form of Phantom Unit Award Agreement (incorporated by reference from Exhibit 10.10 to Amendment No. 3 to ENP’s Registration Statement on Form S-1, filed with the SEC on August 10, 2007).    
  10 .9   Purchase and Sale Agreement, dated May 18, 2009, by and among Encore Energy Partners LP, Encore Energy Partners Operating LLC, and Encore Operating, L.P. (incorporated by reference from Exhibit 2.1 of ENP’s Current Report on Form 8-K, filed with the SEC on June 5, 2009).    
  10 .10   Purchase and Sale Agreement, dated June 28, 2009, by and among Encore Energy Partners LP, Encore Energy Partners Operating LLC, and Encore Operating, L.P. (incorporated by reference from Exhibit 2.1 of ENP’s Current Report on Form 8-K, filed with the SEC on June 29, 2009).    
  12 .1*   Statement showing computation of ratio of earnings (loss) to fixed charges.    
  21 .1*   Subsidiaries of Encore Energy Partners LP as of February 22, 2010.    
  23 .1*   Consent of Ernst & Young LLP.    
  23 .2*   Consent of Miller and Lents, Ltd.    
  24 .1*   Power of Attorney (included on the signature page of this Report).    
  31 .1*   Rule 13a-14(a)/15d-14(a) Certification (Principal Executive Officer of our General Partner).    
  31 .2*   Rule 13a-14(a)/15d-14(a) Certification (Principal Financial Officer of our General Partner).    
  32 .1*   Section 1350 Certification (Principal Executive Officer of our General Partner).    
  32 .2*   Section 1350 Certification (Principal Financial Officer of our General Partner).    
  99 .1*   Miller and Lents, Ltd. report on the Reserves and Future Net Revenues of Encore Energy Partners LP as of December 31, 2009.    
 
 
Filed herewith.
 
+ Management contract or compensatory plan, contract, or arrangement.

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ENCORE ENERGY PARTNERS LP
 
SIGNATURES
 
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
 
ENCORE ENERGY PARTNERS LP
 
By: Encore Energy Partners GP LLC, its General Partner
 
     
Date: February 22, 2010
 
By: 
/s/  Jon S. Brumley

Jon S. Brumley
Chief Executive Officer and President
 
KNOW ALL MEN BY THESE PRESENTS, that each individual whose signature appears below constitutes and appoints Jon S. Brumley and Robert C. Reeves, and each of them, his true and lawful attorneys-in-fact and agents with full power of substitution, for him and in his name, place and stead, in any and all capacities, to sign any and all amendments (including post-effective amendments) to this report, and to file the same, with all exhibits thereto, and all documents in connection therewith, with the SEC, granting unto said attorneys-in-fact and agents, full power and authority to do and perform each and every act and thing requisite and necessary to be done in and about the premises, as fully to all intents and purposes as he might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or his or their substitutes, may lawfully do or cause to be done by virtue hereof.
 
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
 
             
        Title or Capacity (Position with Encore
   
Signature
 
Energy Partners GP LLC)
 
Date
 
         
/s/  I. Jon Brumley

I. Jon Brumley
  Chairman of the Board and Director   February 22, 2010
         
/s/  Jon S. Brumley

Jon S. Brumley
  Chief Executive Officer, President, and Director (Principal Executive Officer)   February 22, 2010
         
/s/  Robert C. Reeves

Robert C. Reeves
  Senior Vice President, Chief Financial Officer, Treasurer, and Corporate Secretary (Principal Financial Officer)   February 22, 2010
         
/s/  Andrea Hunter

Andrea Hunter
  Vice President, Controller, and Principal Accounting Officer   February 22, 2010
         
/s/  Arnold L. Chavkin

Arnold L. Chavkin
  Director   February 22, 2010
         
/s/  John E. Jackson

John E. Jackson
  Director   February 22, 2010
         
/s/  J. Luther King, Jr.

J. Luther King, Jr.
  Director   February 22, 2010
         
/s/  Clayton E. Melton

Clayton E. Melton
  Director   February 22, 2010
         
/s/  George W. Passela

George W. Passela
  Director   February 22, 2010


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