10-Q 1 d56723e10vq.htm FORM 10-Q e10vq
Table of Contents

 
 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
     
þ   QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2008
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   (I.R.S. Employer
incorporation or organization)   Identification No.)
     
777 Main Street, Suite 1400, Fort Worth, Texas   76102
     
(Address of principal executive offices)   (Zip Code)
(817) 877-9955
(Registrant’s telephone number, including area code)
Not applicable
(Former name, former address and former fiscal year, if changed since last report)
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 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 o   Non-accelerated filer þ   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 Exchange Act). Yes o   No þ
         
Number of common units outstanding as of May 2, 2008
  31,356,155  
 
 

 


 

ENCORE ENERGY PARTNERS LP
INDEX
         
    Page  
PART I. FINANCIAL INFORMATION
 
       
       
 
       
    1  
 
       
    2  
 
       
    3  
 
       
    4  
 
       
    5  
 
       
    18  
 
       
    27  
 
       
    28  
 
       
PART II. OTHER INFORMATION
 
       
    28  
 
       
    28  
 
       
    28  
 
       
    28  
 
       
    30  
 Rule 13a-14(a)/15d-14(a) Certification
 Rule 13a-14(a)/15d-14(a) Certification
 Section 1350 Certification
 Section 1350 Certification
 Statement Showing Computation of Ratio of Earnings to Fixed Charges
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION
     Certain information included in this Quarterly Report on Form 10-Q (the “Report”) and other materials filed with the Securities and Exchange Commission (“SEC”), or in other written or oral statements made or to be made by us, other than statements of historical fact, are forward-looking statements. These forward-looking statements 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. Readers 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” in our Annual Report on Form 10-K for the year ended December 31, 2007 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.

i


Table of Contents

ENCORE ENERGY PARTNERS LP
GLOSSARY
     The following are abbreviations and definitions of certain terms, including oil and natural gas industry terms, used in this 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.
    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.
 
    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.
 
    Council of Petroleum Accountants Societies (“COPAS”). A professional organization of oil and 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 commencement of production from a well.
 
    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. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production would exceed production expenses and taxes.
 
    EAC. Encore Acquisition Company, a publicly traded Delaware corporation, together with its subsidiaries.
 
    ENP or the Partnership. Encore Energy Partners LP, a Delaware limited partnership, together with its subsidiaries.
 
    Exploratory Well. A well drilled to find and produce oil or natural gas in an unproved area, to find a new reservoir in a field previously producing oil or natural gas in another reservoir, or to extend a known reservoir.
 
    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.
 
    Gross Wells. The total number of wells in which an entity owns a working interest.
 
    Lease Operations Expense (“LOE”). All direct and allocated indirect costs of producing oil and natural gas after completion of drilling. 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.
 
    MMcf. One million cubic feet, used in reference to natural gas.
 
    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 Production. An entity’s share of crude oil and natural gas produced from a property, less royalties paid to landowners and production quantities due others.
 
    Net Profits Interest. An interest that entitles the owner to a specified share of net profits from production of hydrocarbons.
 
    Net Wells. Gross wells multiplied by the percentage working interest owned by an entity.
 
    NYMEX. New York Mercantile Exchange.
 
    Oil. Crude oil, condensate, and NGLs.
 
    Operator. The entity responsible for the exploration, development, and production of an oil or natural gas well or lease.
 
    Production Margin. Oil and natural gas revenues less LOE and production, ad valorem, and severance taxes.
 
    Proved Developed Reserves. Proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.
 
    Proved Reserves. The estimated quantities of crude oil, natural gas, and NGLs which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.
 
    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. Proved undeveloped reserves include unrealized

ii


Table of Contents

ENCORE ENERGY PARTNERS LP
      production response from fluid injection and other improved recovery techniques, where such techniques have been proved effective by actual tests in the area and in the same reservoir.
 
    Recompletion. The completion for production of an existing well bore in another formation from that in which the well has been previously completed.
 
    Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
 
    Royalty. An interest in an oil or natural gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale of production), but does not require the owner to pay any portion of the costs of drilling or operating the wells 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.
 
    Secondary Recovery. Enhanced recovery of oil or natural gas from a reservoir beyond the oil or natural gas that can be recovered by normal flowing and pumping operations. Secondary recovery techniques involve maintaining or enhancing reservoir pressure by injecting water, gas, or other substances into the formation. The purpose of secondary recovery is to maintain reservoir pressure and to displace hydrocarbons toward the wellbore. The most common secondary recovery techniques are gas injection and waterflooding.
 
    Successful Well. A well capable of producing oil and/or natural gas in commercial quantities.
 
    Tertiary Recovery. An enhanced recovery operation that normally occurs after waterflooding in which chemicals or natural gases are used as the injectant.
 
    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 of the interest the right to drill for and produce oil and natural gas on the leased acreage and requires the owner to pay a share of the costs of drilling and production operations.
 
    Workover. Operations on a producing well to restore or increase production.

iii


Table of Contents

PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
ENCORE ENERGY PARTNERS LP
CONSOLIDATED BALANCE SHEETS
(in thousands, except unit amounts)
(unaudited)
                 
    March 31,     December 31,  
    2008     2007 *  
ASSETS
Current assets:
               
Cash and cash equivalents
  $ 5     $ 3  
Accounts receivable:
               
Trade
    27,754       21,595  
Affiliate
    819       3,290  
Derivatives
    1,308       3,713  
Other
    1,312       448  
 
           
Total current assets
    31,198       29,049  
 
           
Properties and equipment, at cost — successful efforts method:
               
Proved properties, including wells and related equipment
    506,105       500,470  
Unproved properties
    279       298  
Accumulated depletion, depreciation, and amortization
    (72,340 )     (63,295 )
 
           
 
    434,044       437,473  
 
           
Other property and equipment
    672       510  
Accumulated depreciation
    (108 )     (68 )
 
           
 
    564       442  
 
           
Goodwill
    2,648       2,648  
Other intangibles, net
    3,892       3,969  
Derivatives
    11,001       21,875  
Other
    1,559       2,263  
 
           
Total assets
  $ 484,906     $ 497,719  
 
           
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
               
Accounts payable:
               
Trade
  $ 1,767     $ 1,915  
Affiliate
    3,632       6,709  
Accrued liabilities:
               
Lease operations expense
    2,038       2,903  
Development capital
    3,639       3,012  
Interest
    276       147  
Production, ad valorem, and severance taxes
    8,460       6,272  
Natural gas purchases
    1,268       1,578  
Derivatives
    5,047       865  
Other
    2,154       2,898  
 
           
Total current liabilities
    28,281       26,299  
Derivatives
    19,116       20,447  
Future abandonment cost, net of current portion
    8,438       8,314  
Deferred taxes
    212       130  
Long-term debt
    165,000       47,500  
Other
    53       16  
 
           
Total liabilities
    221,100       102,706  
 
           
Commitments and contingencies (see Note 12)
               
Partners’ equity:
               
Limited partners - 31,072,455 and 24,187,679 common units issued and outstanding, respectively
    265,354       391,956  
General partner - 504,851 general partner units outstanding
    20       3,057  
Accumulated other comprehensive loss
    (1,568 )      
 
           
Total partners’ equity
    263,806       395,013  
 
           
Total liabilities and partners’ equity
  $ 484,906     $ 497,719  
 
           
 
*   Recast as discussed in Note 2.
The accompanying notes are an integral part of these consolidated financial statements.

1


Table of Contents

ENCORE ENERGY PARTNERS LP
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per unit amounts)
(unaudited)
                 
    Three months ended  
    March 31,  
    2008     2007 *  
Revenues:
               
Oil
  $ 37,195     $ 8,160  
Natural gas
    7,002       4,613  
Marketing and other
    2,859       1,238  
 
           
Total revenues
    47,056       14,011  
 
           
 
               
Expenses:
               
Production:
               
Lease operations
    6,058       2,691  
Production, ad valorem, and severance taxes
    4,798       1,475  
Depletion, depreciation, and amortization
    9,120       3,706  
Exploration
    29       31  
General and administrative
    2,922       555  
Marketing
    2,393       1,080  
Derivative fair value loss
    15,587       3,683  
Other operating
    351       145  
 
           
Total expenses
    41,258       13,366  
 
           
 
               
Operating income
    5,798       645  
 
           
 
               
Other income (expenses):
               
Interest
    (1,640 )     (1,102 )
Other
    17        
 
           
Total other income (expenses)
    (1,623 )     (1,102 )
 
           
 
               
Income (loss) before income taxes
    4,175       (457 )
 
               
Income tax provision
    (90 )     (32 )
 
           
 
               
Net income (loss)
  $ 4,085     $ (489 )
 
           
 
               
Net income allocation (see Note 10):
               
Limited partners’ interest in net income
  $ 383          
 
             
General partner’s interest in net income
  $ 35          
 
             
 
               
Net income per common unit:
               
Basic
  $ 0.01          
Diluted
  $ 0.01          
 
               
Weighted average common units outstanding:
               
Basic
    28,273          
Diluted
    28,632          
 
*   Recast as discussed in Note 2.
The accompanying notes are an integral part of these consolidated financial statements.

2


Table of Contents

ENCORE ENERGY PARTNERS LP
CONSOLIDATED STATEMENT OF PARTNERS’ EQUITY AND COMPREHENSIVE INCOME
(in thousands)
(unaudited)
                                 
                    Accumulated        
                    Other     Total  
    Limited     General     Comprehensive     Partners’  
    Partners     Partner     Loss     Equity  
Balance at December 31, 2007 *
  $ 391,956     $ 3,057     $     $ 395,013  
Deemed distributions to affiliates in connection with acquisition of Permian and Williston Basin assets
    (122,003 )     (2,944 )           (124,947 )
Non-cash unit-based compensation
    1,040       18             1,058  
Cash distributions to unitholders
    (9,639 )     (196 )           (9,835 )
Components of comprehensive income:
                               
Net income attributable to affiliates related to pre-partnership operations of the Permian and Williston Basin assets
    3,321       80             3,401  
Net income attributable to unitholders
    679       5             684  
Change in unrealized hedge loss on interest rate swap agreements
                (1,568 )     (1,568 )
 
                             
Total comprehensive income
                            2,517  
 
                       
Balance at March 31, 2008
  $ 265,354     $ 20     $ (1,568 )   $ 263,806  
 
                       
 
*   Recast as discussed in Note 2.
The accompanying notes are an integral part of these consolidated financial statements.

3


Table of Contents

ENCORE ENERGY PARTNERS LP
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
(unaudited)
                 
    Three months ended  
    March 31,  
    2008     2007*  
Cash flows from operating activities:
               
Net income (loss)
  $ 4,085     $ (489 )
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
               
Depletion, depreciation, and amortization
    9,120       3,706  
Non-cash exploration expense
    20       5  
Non-cash unit-based compensation expense
    1,058        
Non-cash derivative fair value loss
    15,758       3,683  
Deferred taxes
    38       3  
Other
    390       539  
Changes in operating assets and liabilities, net of effects from acquisition:
               
Accounts receivable
    (3,233 )     (4,823 )
Other current assets
    (820 )     (20 )
Long-term derivatives
    (1,196 )     (2,051 )
Other assets
    766       (456 )
Accounts payable
    (3,225 )     (817 )
Other current liabilities
    187       3,605  
 
           
Net cash provided by operating activities
    22,948       2,885  
 
           
 
               
Cash flows from investing activities:
               
Purchases of other property and equipment
    (162 )      
Acquisition of oil and natural gas properties
          (328,464 )
Development of oil and natural gas properties
    (4,858 )     (1,206 )
 
           
Net cash used in investing activities
    (5,020 )     (329,670 )
 
           
 
               
Cash flows from financing activities:
               
Proceeds from long-term debt, net of issuance costs
    142,310       245,883  
Payments on long-term debt
    (25,000 )     (8,383 )
Deemed distributions to affiliates in connection with acquisition of Permian and Williston Basin assets
    (125,401 )      
Distributions to unitholders
    (9,835 )      
Contribution by EAC in connection with purchase of Elk Basin assets
          93,658  
Distributions to owner prior to IPO
          (3,853 )
 
           
Net cash provided by (used in) financing activities
    (17,926 )     327,305  
 
           
 
               
Increase in cash and cash equivalents
    2       520  
Cash and cash equivalents, beginning of period
    3        
 
           
Cash and cash equivalents, end of period
  $ 5     $ 520  
 
           
 
               
Non-cash financing activities:
               
Issuance of common units in connection with acquisition of Permian and Williston Basin assets (see Note 3)
               
 
*   Recast as discussed in Note 2.
The accompanying notes are an integral part of these consolidated financial statements.

4


Table of Contents

ENCORE ENERGY PARTNERS LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
Note 1. Description of Business
     Encore Energy Partners LP (“ENP” or the “Partnership”) was formed in February 2007 by Encore Acquisition Company (“EAC”) to acquire, exploit, and develop oil and natural gas properties and to acquire, own, and operate related assets. Also in February 2007, Encore Energy Partners GP LLC (the “General Partner”), a Delaware limited liability company and wholly owned subsidiary of EAC, was formed to serve as the general partner of ENP, and Encore Energy Partners Operating LLC (“OLLC”), a Delaware limited liability company and wholly owned subsidiary of the Partnership, was formed to own and operate ENP’s properties.
     The Partnership’s properties consist of: (1) oil and natural gas properties and related assets in the Big Horn Basin of Wyoming and Montana, primarily in the Elk Basin field, (the “Elk Basin Assets”), which the Partnership acquired in March 2007 from certain subsidiaries of Anadarko Petroleum Corporation (“Anadarko”); (2) oil and natural gas properties and related assets in the Permian Basin of West Texas (the “Permian Basin Assets”), which EAC contributed to the Partnership upon completion of the Partnership’s initial public offering (“IPO”) in September 2007; and (3) oil and natural gas properties and related assets in the Permian Basin of West Texas and the Williston Basin of North Dakota (the “Permian and Williston Basin Assets”), which were acquired from EAC in February 2008. See “Note 3. Acquisitions” for additional discussion.
Initial Public Offering and Concurrent Transactions
     On September 17, 2007, the Partnership completed its IPO. At the closing of the IPO, the following transactions were completed:
  (a)   The Partnership entered into a contribution, conveyance and assumption agreement (the “Contribution Agreement”) with the General Partner, OLLC, EAC, Encore Operating, L.P., a Texas limited partnership and indirect wholly owned subsidiary of EAC (“Encore Operating”), and Encore Partners LP Holdings LLC. The following transactions, among others, occurred pursuant to the Contribution Agreement:
    Encore Operating transferred the Permian Basin Assets to the Partnership in exchange for 4,043,478 common units; and
 
    EAC agreed to indemnify the Partnership 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 the Partnership in exchange for the Permian Basin Assets, the IPO, and the exercise of the underwriters’ option to purchase additional common units, the General Partner exchanged a certain number of common units for general partner units to enable it to maintain its then 2 percent general partner interest.
 
  (b)   The Partnership entered into an amended and restated administrative services agreement (the “Administrative Services Agreement”) with the General Partner, OLLC, Encore Operating, and EAC, whereby Encore Operating performs administrative services for the Partnership, such as accounting, corporate development, finance, land, legal, and engineering. In addition, Encore Operating provides all personnel and any facilities, goods, and equipment necessary to perform these services and not otherwise provided by the Partnership. Encore Operating initially received an administrative fee of $1.75 per BOE of the Partnership’s production for such services. Encore Operating also charges the Partnership for reimbursement of actual third-party expenses incurred on the Partnership’s behalf. Encore Operating has substantial discretion in determining which third-party expenses to incur on the Partnership’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 of a well. Encore Operating is not liable to the Partnership 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. Effective April 1, 2008, the administrative fee per the Administrative Services Agreement increased to $1.84 per BOE of the Partnership’s production as a result of the COPAS Wage Index Adjustment for the current year.

5


Table of Contents

ENCORE ENERGY PARTNERS LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued

(unaudited)
      The Partnership reimburses EAC for any additional state income, franchise, or similar tax paid by EAC resulting from the inclusion of the Partnership in a combined state income, franchise, or similar tax report with EAC as required by applicable law. The amount of any such reimbursement is limited to the tax that the Partnership would have paid had it not been included in a combined group with EAC. See “Note 13. Related Party Transactions” for additional discussion regarding the Administrative Services Agreement.
 
  (c)   The Encore Energy Partners GP LLC Long-Term Incentive Plan (the “ENP Incentive Plan”) was approved by the General Partner, which applies to employees, consultants, and directors of EAC, the General Partner, and any of their affiliates who perform services for the Partnership. See “Note 11. Unit-Based Compensation Plans” for additional discussion regarding the ENP Incentive Plan.
Note 2. Basis of Presentation
     The Partnership’s consolidated financial statements include the accounts of its wholly owned subsidiaries. All material intercompany balances and transactions have been eliminated in consolidation.
     The Permian Basin Assets are considered the predecessor to the Partnership (the “Predecessor”), and therefore, the historical results of operations of the Partnership include the results of operations of the Permian Basin Assets for all periods presented. The results of operations of the Elk Basin Assets have been included with those of the Partnership from the date of acquisition on March 7, 2007. In February 2008, the Partnership completed the acquisition of the Permian and Williston Basin Assets from Encore Operating. See “Note 3. Acquisitions” for additional discussion. Because the Permian and Williston Basin Assets were acquired from an affiliate, the acquisition was accounted for as a transaction between entities under common control, similar to a pooling, whereby the assets and liabilities were recorded at Encore Operating’s historical cost and the Partnership’s historical financial information was recast to include the acquired properties for all periods presented. Accordingly, the consolidated financial statements and notes thereto reflect the combined historical results of the Partnership, the Permian Basin Assets, and the Permian and Williston Basin Assets throughout the periods presented. The effect of recasting the Partnership’s consolidated financial statements to account for this common control transaction reduced the Partnership’s net loss by $2.4 million for the first quarter of 2007.
     The Partnership, the Permian Basin Assets, and the Permian and Williston Basin Assets were wholly 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.
     In the opinion of management, the accompanying unaudited consolidated financial statements include all adjustments necessary to present fairly, in all material respects, its financial position as of March 31, 2008 and its results of operations and cash flows for the three months ended March 31, 2008 and 2007. All adjustments are of a normal recurring nature. These interim results are not necessarily indicative of results for an entire year.
     Certain amounts and disclosures have been condensed or omitted from these consolidated financial statements pursuant to the rules and regulations of the SEC. Therefore, these consolidated financial statements should be read in conjunction with the consolidated financial statements and the related notes thereto included in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2007.
New Accounting Pronouncements
Statement of Financial Accounting Standards (“SFAS”) No. 157, “Fair Value Measurements” (“SFAS 157”)
     In September 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS 157. SFAS 157 standardizes the definition of fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures related to the use of fair value measures in financial statements. SFAS 157 applies whenever other standards require (or permit) assets or liabilities to be measured at fair value but does not require any new fair value measurements. In February 2008, the FASB issued FASB Staff Position (“FSP”) No. FAS 157-2, “Effective Date of FASB Statement No. 157” (“FSP FAS 157-2”), which delayed the effective date of SFAS 157 for one year for nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). The Partnership elected a partial deferral of SFAS 157 for all instruments within the scope of FSP FAS 157-2, including but not limited to, its asset retirement obligations and indefinite lived assets. The Partnership will continue to evaluate

6


Table of Contents

ENCORE ENERGY PARTNERS LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued

(unaudited)
the impact of SFAS 157 on these instruments during the deferral period. The adoption of SFAS 157 on January 1, 2008 did not have a material impact on the Partnership’s results of operations or financial condition. See “Note 6. Fair Value Measurements” for additional discussion and related disclosures of the Partnership’s assets and liabilities measured at fair value.
SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities — including an amendment of FASB Statement No. 115” (“SFAS 159”)
     In February 2007, the FASB issued SFAS 159. SFAS 159 permits entities to measure many financial instruments and certain other assets and liabilities at fair value on an instrument-by-instrument basis. SFAS 159 allows entities an irrevocable option to measure eligible items at fair value at specified election dates, with resulting changes in fair value reported in earnings. SFAS 159 was effective for the Partnership on January 1, 2008; however, the Partnership did not elect the fair value option for eligible instruments existing on that date. Therefore, SFAS 159 did not have an impact on the Partnership’s results of operations or financial condition. The Partnership will assess the impact of electing the fair value option for any newly acquired eligible instruments. Electing the fair value option for such instruments could have a material impact on the Partnership’s future results of operations or financial condition.
SFAS No. 141 (revised 2007), “Business Combinations” (“SFAS 141R”)
     In December 2007, the FASB issued SFAS 141R, which replaces SFAS No. 141, “Business Combinations.” SFAS 141R establishes principles and requirements for the reporting entity in a business combination, including: (i) recognition and measurement in the financial statements of the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree; (ii) recognition and measurement of goodwill acquired in the business combination or a gain from a bargain purchase; and (iii) determination of the information to be disclosed to enable financial statement users to evaluate the nature and financial effects of the business combination. SFAS 141R applies prospectively to business combinations consummated in fiscal years beginning on or after December 15, 2008 (for acquisitions closed on or after January 1, 2009 for the Partnership). Early application is prohibited. The Partnership is evaluating the impact SFAS 141R will have on its results of operations and financial condition and the reporting of future acquisitions in the consolidated financial statements.
SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities — an amendment of FASB Statement No. 133” (“SFAS 161”)
     In March 2008, the FASB issued SFAS 161. SFAS 161 amends SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” (“SFAS 133”) to require enhanced disclosures about (i) how and why an entity uses derivative instruments; (ii) how derivative instruments and related hedged items are accounted for under SFAS 133 and its related interpretations; and (iii) how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. SFAS 161 is effective for fiscal years beginning on or after November 15, 2008, with early application encouraged. The adoption of SFAS 161 will require additional disclosures regarding the Partnership’s derivative instruments; however, the Partnership does not expect the adoption to have a material impact on its results of operations or financial condition.
Emerging Issues Task Force (“EITF”) Issue No. 07-4, “Application of the Two-Class Method under FASB Statement No. 128, Earnings per Share, to Master Limited Partnerships” (“EITF 07-4”)
     In March 2008, the EITF ratified its consensus opinion on EITF 07-4. EITF 07-4 addresses how master limited partnerships should calculate earnings per unit using the two-class method in SFAS No. 128, “Earnings per Share” (“SFAS 128”) and how current period earnings of a master limited partnership should be allocated to the general partner, limited partners, and other participating securities. EITF 07-4 is effective for fiscal years beginning after December 15, 2008, and interim periods within those years. EITF 07-4 should be applied retrospectively for all periods presented. The Partnership is currently evaluating the impact that EITF 07-4 will have on its earnings per unit calculation.

7


Table of Contents

ENCORE ENERGY PARTNERS LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued

(unaudited)
Note 3. Acquisitions
Permian and Williston Basin Assets
     On December 27, 2007, OLLC entered into a purchase and investment agreement with Encore Operating pursuant to which OLLC agreed to acquire the Permian and Williston Basin Assets. The transaction closed on February 7, 2008. The total consideration for the acquisition consisted of approximately $125.4 million in cash, including certain closing adjustments, and 6,884,776 common units representing limited partner interests in the Partnership. In determining the total purchase price of the Permian and Williston Basin Assets, the common units were valued at $125 million. The cash portion of the purchase price was financed with additional borrowings under OLLC’s revolving credit facility.
     As discussed in “Note 2. Basis of Presentation,” the transaction 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 historical cost of approximately $100 million, and the historical financial information of the Partnership has been recast to include the results of the Permian and Williston Basin Assets for all periods presented. As the historical basis in the Permian and Williston Basin Assets is included in the Consolidated Balance Sheet as of December 31, 2007, the cash purchase price, as adjusted for certain closing adjustments, of the Permian and Williston Basin Assets was recorded as a deemed distribution to the EAC affiliates based on their respective ownership percentages in the Partnership’s general and limited partner units. No value was ascribed to the common units issued as consideration for the acquired properties.
Elk Basin Assets
     On January 16, 2007, EAC entered into a purchase and sale agreement with certain subsidiaries of Anadarko to acquire oil and natural gas properties and related assets in the Big Horn Basin of Wyoming and Montana, which included the Elk Basin Assets. Prior to closing, EAC assigned the rights and duties under the purchase and sale agreement relating to the Elk Basin Assets to OLLC. The closing of the acquisition occurred on March 7, 2007 after which the operations of the Elk Basin Assets have been included with those of the Partnership. At closing, OLLC paid approximately $328.4 million for the Elk Basin Assets. The total purchase price for the Elk Basin Assets was $330.7 million, including post-closing adjustments and $1.1 million of transaction costs.
     The following displays the calculation of the total purchase price and the allocation to the fair value of the assets acquired and liabilities assumed from Anadarko (in thousands):
         
Calculation of total purchase price:
       
Cash paid to Anadarko
  $ 329,551  
Transaction costs
    1,110  
 
     
Total purchase price
  $ 330,661  
 
     
 
       
Allocation of purchase price to the fair value of net assets acquired:
       
Proved properties, including wells and related equipment
  $ 332,549  
Intangibles
    4,225  
Other property and equipment
    346  
Accounts receivable
    1,444  
 
     
Total assets acquired
    338,564  
 
     
Current liabilities
    (1,120 )
Future abandonment cost and assumed liabilities
    (6,783 )
 
     
Total liabilities assumed
    (7,903 )
 
     
Fair value of net assets acquired
  $ 330,661  
 
     
     The proved properties amount in the above purchase price allocation includes the fair value of proved leasehold costs, lease and well equipment (including flue gas reinjection facilities used to maintain reservoir pressure by compressing and reinjecting the gas produced), and an oil pipeline and natural gas pipeline used primarily to transport production from the acquired fields. NGLs are produced as a byproduct of the flue gas tertiary recovery project and are sold at market prices. The revenues generated by NGLs are included in “Oil revenues” in the accompanying Consolidated Statements of Operations. Third party revenues and expenses related to the pipelines are included in “Marketing and other revenues” and “Marketing expense,” respectively, in the accompanying Consolidated Statements of Operations.

8


Table of Contents

ENCORE ENERGY PARTNERS LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued

(unaudited)
     The Partnership financed the acquisition of the Elk Basin Assets through a $93.7 million contribution from EAC and borrowings under its long-term debt agreements. See “Note 8. Debt” for additional discussion of the Partnership’s long-term debt.
     The following unaudited pro forma condensed financial data for the three months ended March 31, 2007 was derived from the historical financial statements of the Partnership and from the accounting records of Anadarko 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 as of January 1, 2007 and is not intended to be a projection of future results.
         
    Three Months  
    Ended March 31,  
    2007  
    (in thousands)  
Pro forma total revenues
  $ 28,172  
 
     
 
       
Pro forma net loss
  $ (2,549 )
 
     
     During the three months ended March 31, 2007, the Partnership was wholly owned by EAC. Accordingly, pro forma earnings per unit has not been calculated.
Note 4. Proved Properties
     Amounts shown in the accompanying Consolidated Balance Sheets as “Proved properties” include leasehold costs and wells and related equipment, both completed and in process, and consisted of the following as of the dates indicated:
                 
    March 31,     December 31,  
    2008     2007  
    (in thousands)  
Proved leasehold costs
  $ 372,077     $ 372,076  
Wells and related equipment — Completed
    129,368       124,381  
Wells and related equipment — In process
    4,660       4,013  
 
           
Total proved properties
  $ 506,105     $ 500,470  
 
           
Note 5. Derivative Financial Instruments
Commodity Derivative Contracts — Mark-to-Market Accounting
     In order to partially finance the cost of premiums on certain purchased floors, the Partnership may sell floors with a strike price below the strike price of the purchased floor. Together the two floors, known as a floor spread or put spread, have a lower premium cost than a traditional floor contract but provide price protection only down to the strike price of the short floor. As with the Partnership’s other commodity derivative contracts, these are marked-to-market each quarter through “Derivative fair value loss” in the accompanying Consolidated Statements of Operations. In the following table, the purchased floor component and the short floor component of these floor spreads has been shown net and included with the Partnership’s other floor contracts.

9


Table of Contents

ENCORE ENERGY PARTNERS LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued

(unaudited)
     The following tables summarize the Partnership’s open commodity derivative instruments as of March 31, 2008:
Oil Derivative Contracts
                                                               
    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)  
April — Dec. 2008
                                                        $ 143  
 
    880     $ 80.00         440     $ 107.60             $            
 
    2,000       75.00                                        
 
    500       65.00                                        
2009
                                                          (7,375 )
 
    880       80.00         440       97.75                          
 
    2,250       74.11                       1,000       68.70            
2010
                                                          (3,662 )
 
    880       80.00         440       93.80                          
 
    2,000       75.00         1,000       77.23                          
2011
                                                          450  
 
    1,880       80.00         1,440       95.41                          
 
    1,000       70.00                                        
 
                                                           
 
                                                        $ (10,444 )
 
                                                           
Natural Gas Derivative Contracts
                                                               
    Daily     Average       Daily     Average       Daily     Average       Asset (Liability)  
    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)  
April — Dec. 2008
                                                        $ (726 )
 
    3,800     $ 8.20         3,800     $ 9.83             $            
 
    3,800       7.20                                        
2009
                                                          (163 )
 
    3,800       8.20         3,800       9.83                          
 
    3,800       7.20                                        
2010
                                                          665  
 
    3,800       8.20         3,800       9.58                          
 
    3,800       7.20                                        
 
                                                           
 
                                                        $ (224 )
 
                                                           
Interest Rate Swap Agreements
     In the first quarter of 2008, as a result of the increase in debt levels, the Partnership entered into interest rate swap agreements whereby it swapped $100 million of floating rate debt to a fixed rate on its revolving credit facility. These interest rate swap agreements were designated as cash flow hedges. The following table summarizes the Partnership’s open interest rate swap agreements as of March 31, 2008:
                         
    Notional   Fixed   Floating
Term   Amount   Rate   Rate
    (in thousands)                
March 2008-January 2011
  $ 50,000       3.1610 %   1 month LIBOR
March 2008-January 2011
    25,000       2.9650 %   1 month LIBOR
March 2008-January 2011
    25,000       2.9613 %   1 month LIBOR
     As of March 31, 2008, the fair market value of the Partnership’s interest rate swap agreements was a net liability of $1.2 million, composed of $0.5 million included in “Current derivatives liability” and $0.7 million included in “Long-term derivatives liability.” During the three months ended March 31, 2008, settlements of interest rate swap agreements reduced the Partnership’s interest expense by approximately $18,000.

10


Table of Contents

ENCORE ENERGY PARTNERS LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued

(unaudited)
Current Period Impact
     As a result of derivative transactions, the Partnership recognized derivative fair value gains and losses related to (i) changes in the market value of commodity derivative contracts, (ii) settlements on commodity derivative contracts, (iii) premium amortization, and (iv) changes in the market value of interest rate swap agreements prior to designation. The following table summarizes the components of derivative fair value loss for the periods indicated:
                 
    Three months ended March 31,  
    2008     2007  
    (in thousands)  
Mark-to-market loss on commodity derivative contracts
  $ 14,002     $ 3,683  
Premium amortization
    2,137        
Change in fair value of interest rate swap agreements prior to designation
    (381 )      
Settlements on commodity derivative contracts
    (171 )      
 
           
Total derivative fair value loss
  $ 15,587     $ 3,683  
 
           
Accumulated Other Comprehensive Loss (“AOCL”)
     At March 31, 2008, AOCL consisted entirely of deferred losses on the Partnership’s interest rate swap agreements. The Partnership expects to reclassify $0.5 million of deferred losses associated with its interest rate swap agreements from AOCL to interest expense during the twelve months ending March 31, 2009.
Note 6. Fair Value Measurements
     As discussed in “Note 2. Basis of Presentation,” the Partnership adopted SFAS 157 effective January 1, 2008, which, among other things, requires enhanced disclosures about assets and liabilities carried at fair value.
     As defined in SFAS 157, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The Partnership utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. The Partnership primarily applies the market and income approaches for recurring fair value measurements and utilizes the best available information. Accordingly, the Partnership utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The Partnership has reviewed its recurring transactions and found that its markets and financial instruments are fairly liquid and has established that they are able to transact at the midpoint of the bid/ask spread. The Partnership is able to classify fair value balances based on the observability of those inputs.
     SFAS 157 establishes a three-tier fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy defined by SFAS 157 are as follows:
    Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
 
    Level 2 — Pricing inputs, other than quoted prices within Level 1, that are observable for the asset or liability, either directly or indirectly, as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data, or are supported by observable levels at which transactions are executed in the marketplace.

11


Table of Contents

ENCORE ENERGY PARTNERS LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-Continued

(unaudited)
    Level 3 — Pricing inputs include significant unobservable inputs. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. At each balance sheet date, the Partnership performs an analysis of all instruments subject to SFAS 157 and includes in Level 3 all of those instruments whose fair value is based on significant unobservable inputs.
     The carrying value of the Partnership’s cash and cash equivalents, accounts receivable, and accounts payable approximate their respective fair value due to the relatively short term of the instruments. The carrying amount of long-term debt approximates fair value as the interest rate is variable. These assets and liabilities are not presented in the following tables.
     The following table sets forth by level within the fair value hierarchy the Partnership’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2008. As required by SFAS 157, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Partnership’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.
                                 
            Fair Value Measurements at Reporting Date Using  
            Quoted Prices in              
            Active Markets for     Significant Other     Significant  
    March 31,     Identical Assets     Observable Inputs     Unobservable Inputs  
    2008     (Level 1)     (Level 2)     (Level 3)  
    (in thousands)  
Oil derivative contracts — swaps
  $ (9,364 )   $     $ (9,364 )   $  
Oil derivative contracts — floors and caps
    (1,080 )                 (1,080 )
Natural gas derivative contracts — floors and caps
    (224 )                 (224 )
Interest rate swap agreements
    (1,186 )           (1,186 )      
 
                       
Total
  $ (11,854 )   $     $ (10,550 )   $ (1,304 )
 
                       
     The following table provides a reconciliation of the fair value of the Partnership’s net financial liabilities that were accounted for at fair value on a recurring basis using significant unobservable inputs (Level 3) for the three months ended March 31, 2008:
                         
    Fair Value Measurements Using Significant Unobservable  
    Inputs  
    (Level 3)  
    Oil Derivative     Natural Gas        
    Contracts - Floors     Derivative Contracts        
    and Caps     - Floors and Caps     Total  
    (in thousands)  
Balance at January 1, 2008
  $ 6,466     $ 4,533     $ 10,999  
Total gains (losses):
                       
Included in earnings
    (8,742 )     (4,586 )     (13,328 )
Purchases, issuances, and settlements
    1,196       (171 )     1,025  
 
                 
Balance at March 31, 2008
  $ (1,080 )   $ (224 )   $ (1,304 )
 
                 
 
                       
The amount of total 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
  $ (8,742 )   $ (4,586 )   $ (13,328 )
 
                 
     The Partnership does not use hedge accounting for its commodity derivative contracts; therefore, all derivative fair value gains and losses are included in “Derivative fair value loss” on the accompanying Consolidated Statements of Operations.
     The following methods and assumptions were used to estimate the fair values of the net liabilities in the table above. As per the requirements under SFAS 157, all fair values reflected in the table above and on the accompanying Consolidated Balance Sheet

12


Table of Contents

ENCORE ENERGY PARTNERS LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued

(unaudited)
as of March 31, 2008 have been adjusted for non-performance risk. The adjustment to fair value related to non-performance risk as of March 31, 2008 was a reduction of the net liability value of approximately $0.4 million.
Level 1 Fair Value Measurements
     As of March 31, 2008, the Partnership did not have any assets or liabilities measured under the Level 1 fair value hierarchy.
Level 2 Fair Value Measurements
     Oil derivative contracts — swaps — The fair value of the Partnership’s oil commodity derivative swap was estimated using a combined income and market-based valuation methodology based upon forward commodity prices. Forward curves were obtained from independent pricing services reflecting broker market quotes.
     Interest rate swap agreements — The fair values of the interest rate swap agreements were estimated using a combined income and market-based valuation methodology based upon forward interest rate yield curves and credit. The curves were obtained from independent pricing services reflecting broker market quotes.
Level 3 Fair Value Measurements
     Oil and natural gas derivative contracts — floors and caps — The fair values of the Partnership’s oil and natural gas commodity derivative floors and caps were estimated using pricing models and discounted cash flow methodologies based on inputs that are not readily available in public markets and, accordingly, these floors and caps have been categorized as Level 3 within the valuation hierarchy.
Note 7. Asset Retirement Obligations
     The Partnership’s primary 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 the Partnership’s estimated asset retirement obligations, the long-term portion of which is recorded in “Future abandonment cost, net of current portion” and the short-term portion of which is recorded in “Other current liabilities” on the accompanying Consolidated Balance Sheet, for the three months ended March 31, 2008 (in thousands):
         
Future abandonment liability at January 1, 2008
  $ 8,704  
Wells drilled
    20  
Accretion of discount
    149  
Revision of previous estimates
    (98 )
 
     
Future abandonment liability at March 31, 2008
  $ 8,775  
 
     
Note 8. Debt
Revolving Credit Facility
     In conjunction with the closing of the acquisition of the Elk Basin Assets on March 7, 2007, OLLC entered into a five-year credit agreement (the “OLLC Credit Agreement”) with a bank syndicate comprised of Bank of America, N.A. and other lenders. 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 OLLC Credit Agreement matures on March 7, 2012.
     The aggregate amount of the commitments of the lenders under the OLLC Credit Agreement is $300 million. Availability under the OLLC Credit Agreement is subject to a borrowing base, which is redetermined semi-annually and upon requested special redeterminations. At March 31, 2008, the borrowing base was $240 million.
     As of March 31, 2008, there were $165 million of outstanding borrowings and $74.9 million of borrowing capacity under the OLLC Credit Agreement. As of March 31, 2008, there were $0.1 million of outstanding letters of credit.

13


Table of Contents

ENCORE ENERGY PARTNERS LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued

(unaudited)
     OLLC’s obligations under the OLLC Credit Agreement are secured by a first-priority security interest in OLLC’s and its restricted subsidiaries’ proved oil and natural gas reserves and in the equity interests of OLLC and its restricted subsidiaries. In addition, OLLC’s obligations under the OLLC Credit Agreement are guaranteed by the Partnership and OLLC’s restricted subsidiaries. Obligations under the OLLC Credit Agreement are non-recourse to EAC and its restricted subsidiaries.
     The OLLC Credit Agreement contains customary events of default. 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. At March 31, 2008, OLLC was in compliance with all debt covenants under the OLLC Credit Agreement, as amended.
Subordinated Credit Agreement
     On March 7, 2007, OLLC entered into a six-year subordinated credit agreement with EAP Operating, Inc., an indirect wholly owned subsidiary of EAC. Pursuant to the subordinated credit agreement, a single subordinated term loan was made on March 7, 2007 to the Partnership in the aggregate amount of $120 million. The total outstanding balance of $126.4 million was repaid in September 2007 using a portion of the net proceeds from the IPO.
Note 9. Partners’ Equity and 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 the partnership agreement) to its unitholders. Distributions are not cumulative. The Partnership distributes available cash to its unitholders and the General Partner in accordance with their ownership percentages. In distributing available cash, the Partnership assumes that the holders of management incentive units own the equivalent number of common units into which such units are convertible on the date of distribution, provided that distributions payable to the holders of management incentive units are subject to a maximum limit equal to 5.1 percent of all distributions to the Partnership’s unitholders at the time of any such distribution. If the 5.1 percent maximum limit on aggregate distributions to the holders of management incentive units is reached, then any available cash that would have been distributed to such holders will be available for distribution to unitholders. See “Note 11. Unit-Based Compensation Plans” for additional discussion of the management incentive units.
     On February 14, 2008, the Partnership paid a quarterly distribution of $0.3875 per unit with respect to the fourth quarter of 2007. The total distribution of $9.8 million was paid to unitholders of record as of the close of business on February 6, 2008.
Note 10. Earnings Per Common Unit (“EPU”)
     The Partnership calculates EPU in accordance with SFAS 128. Under the two-class method of calculating EPU as prescribed by SFAS 128, 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 undistributed earnings with common units. For purposes of calculating EPU, the general partner units and management incentive units are participating securities.
     For the first quarter of 2008, EPU was calculated by dividing the limited partners’ interest in net income, after deducting the interests of participating securities, by the weighted average number of common units outstanding. Prior to its IPO in September 2007, the Partnership was wholly owned by EAC, other than management incentive units owned by certain executive officers of the General Partner. Accordingly, EPU is not presented for the first quarter of 2007.

14


Table of Contents

ENCORE ENERGY PARTNERS LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued

(unaudited)
     The following table presents the allocation of net income to the limited partners and reflects EPU computations for the three months ended March 31, 2008 (in thousands, except per unit data):
         
Net income
  $ 4,085  
Less: Net income related to pre-partnership operations of the Permian and Williston Basin Assets
    (3,401 )
 
     
Net income attributable to unitholders
  $ 684  
 
     
 
       
Numerator:
       
Net income attributable to unitholders
  $ 684  
Less: Net income allocation to General Partner
    (35 )
Less: Quarterly distribution to holders of management incentive units
    (266 )
 
     
Net income available to limited partners
  $ 383  
 
     
 
       
Denominator:
       
Denominator for basic EPU:
       
Weighted average common units outstanding
    28,273  
Effect of dilutive management incentive units (a)
    359  
 
     
Denominator for diluted EPU
    28,632  
 
     
 
       
Net income per common unit:
       
Basic
  $ 0.01  
Diluted
  $ 0.01  
 
(a)   A total of 183,333 management incentive units, which represented 286,458 common unit equivalents as of March 31, 2008, were outstanding at March 31, 2008 but were excluded from the above calculation of diluted EPU for the first quarter of 2008 because their effect would be antidilutive. See additional discussion of management incentive units in “Note 11. Unit-Based Compensation Plans.”
Note 11. 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 the executive officers of the General Partner. A management incentive unit is a limited partner interest in the Partnership that entitles the holder to quarterly distributions to the extent paid to the Partnership’s common unitholders and to increasing distributions upon the achievement of 10 percent compounding increases in the Partnership’s distribution rate to common unitholders. Management incentive units are convertible into common units of the Partnership upon the occurrence of any of the following events:
    a change in control;
 
    at the option of the holder, when the Partnership’s aggregate quarterly distributions to unitholders over four consecutive quarters are at least $2.05 per unit; or
 
    the holder’s death or disability.
     In order for distributions payable to the holders of the management incentive units to increase, the distributions payable to common unitholders must increase by 10 percent on a compounded basis. The management incentive units are subject to a maximum limit on the aggregate number of common units issuable to, and the aggregate distributions payable to, holders of management incentive units as follows:
    the holders of management incentive units are not entitled to receive, in the aggregate, common units upon conversion of the management incentive units that exceed a maximum limit of 5.1 percent of all the Partnership’s then-outstanding units; and
 
    the holders of management incentive units are not entitled to receive, in the aggregate, distributions of the Partnership’s available cash in an amount that exceeds a maximum limit of 5.1 percent of all such distributions to all unitholders at the time of any such distribution.

15


Table of Contents

ENCORE ENERGY PARTNERS LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued

(unaudited)
     The holders of management incentive units do not have any voting rights with respect to the units.
     The management incentive units vest in three equal installments. The first installment vested upon the closing of the IPO, and the subsequent vestings will occur on September 17, 2008 and 2009. During the first quarter of 2008, the Partnership recognized total compensation expense of $1.1 million for the management incentive units, which is included in “General and administrative expense” in the accompanying Consolidated Statements of Operations. As of March 31, 2008, ENP had $3.7 million of total unrecognized compensation cost related to unvested management incentive units, which is expected to be recognized over a weighted average period of 0.6 years. For the second and third quarters of 2008, the expense will be approximately $1.1 million per quarter, and for the fourth quarter of 2008 through the third quarter of 2009, the expense will be approximately $0.4 million per quarter. There have not been any additional issuances or forfeitures of management incentive units.
ENP Incentive Plan
     As discussed in “Note 1. Description of Business”, in connection with the IPO, the board of directors of the General Partner adopted the ENP Incentive Plan for employees, consultants, and directors of EAC, the General Partner, and any of their affiliates who perform services for the Partnership. The ENP Incentive Plan provides for the grant of options, restricted units, phantom units, unit appreciation rights, distribution equivalent rights, other unit-based awards, and unit awards. An aggregate of 1,150,000 common units may be delivered pursuant to awards under the ENP Incentive Plan. The ENP Incentive Plan is administered by the board of directors of the General Partner or a committee thereof, referred to as the plan administrator.
     In October 2007, the board of directors of the General Partner issued 20,000 phantom units to directors of the General Partner pursuant to the ENP Incentive Plan. During the first quarter of 2008, the board of directors of the General Partner issued 5,000 phantom units to a new board member pursuant to the ENP Incentive Plan. 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. These phantom units are classified as liability awards under SFAS No. 123 (revised 2004), “Share-Based Payment.” Accordingly, the Partnership determines the fair value of these awards at each reporting period, based on the closing unit price of the Partnership, and recognizes the current portion of the liability as a component of “Other current liabilities” and the long-term portion of the liability as “Other noncurrent liabilities” on the accompanying Consolidated Balance Sheet. As of March 31, 2008, the total liability was $0.1 million. For liability awards, the fair value of the award, which determines the measurement of the liability on the balance sheet, is remeasured at each reporting period until the award is settled. Changes in the fair value of the liability award from period to period are recorded as increases or decreases in compensation expense, over the remaining service period. The phantom units vest in four equal installments on October 29, 2008, 2009, 2010, and 2011. The holders of phantom units are also entitled to receive distribution equivalent rights prior to vesting, which entitle the grantee to receive cash equal to the amount of any cash distributions made by the Partnership with respect to a common unit during the period the right is outstanding.
     The Partnership recognized total compensation expense of approximately $72,000 for the phantom units in the first quarter of 2008, which is included in “General and administrative expense” in the accompanying Consolidated Statements of Operations. There have not been any additional issuances or forfeitures under the ENP Incentive Plan.
     To satisfy common unit awards, the Partnership will issue new common units, acquire common units in the open market, or use common units already owned by EAC and its affiliates.
Note 12. Commitments and Contingencies
     From time to time, the Partnership is a party to various legal proceedings in the ordinary course of business. The Partnership is not currently a party to any litigation or pending claims that it believes would have a material adverse effect its business, financial condition, results of operations, or liquidity.
     Additionally, the Partnership has contractual obligations related to future plugging and abandonment expenses on oil and natural gas properties and related facilities disposal, long-term debt, and derivative contracts as discussed more fully in the notes above. See the contractual obligations and commitments table included in “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Report for contractual obligations as of March 31, 2008.

16


Table of Contents

ENCORE ENERGY PARTNERS LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued

(unaudited)
Note 13. Related Party Transactions
     The Partnership does not have any employees. The employees supporting the operations of the Partnership are employees of EAC. As discussed in “Note 1. Description of Business”, at the closing of the IPO, the Partnership entered into the Administrative Services Agreement with Encore Operating, pursuant to which Encore Operating performs administrative services for the Partnership.
     During the three months ended March 31, 2008, the Partnership paid $1.5 million to Encore Operating for administrative fees under the Administrative Services Agreement (including payment of COPAS recovery) and $0.8 million for reimbursement of actual third-party expenses incurred on the Partnership’s behalf. The Partnership did not make any related party payments to Encore Operating related to the Administrative Services Agreement during the three months ended March 31, 2007. Expenses incurred under the Administrative Services Agreement and third-party expenses invoiced by EAC to the Partnership are included in “General and administrative expenses” in the accompanying Consolidated Statements of Operations. As of March 31, 2008, the Partnership had a payable to EAC of $3.6 million for services provided by Encore Operating, which is reflected in “Accounts payable - affiliate” in the accompanying Consolidated Balance Sheet, and a receivable from EAC of $0.8 million, which is reflected in “Accounts receivable — affiliate” in the accompanying Consolidated Balance Sheet, primarily related to receivables for natural gas production marketed by Encore Operating.
     As discussed in “Note 3. Acquisitions,” the Partnership completed the acquisition of the Permian and Williston Basin Assets from Encore Operating on February 7, 2008 for total consideration of approximately $125.4 million in cash, including certain closing adjustments, and 6,884,776 common units representing limited partner interests in the Partnership.
     On February 14, 2008, the quarterly distribution with respect to the fourth quarter of 2007 was paid to unitholders at a rate of $0.3875 per unit. The Partnership distributed approximately $5.4 million to EAC as holders of 14,039,279 common units and approximately $0.2 million to the General Partner as the holder of 504,851 general partner units.
     Prior to the contribution of the Permian Basin Assets to the Partnership in September 2007 and the acquisition of the Permian and Williston Basin Assets in February 2008, these properties were wholly owned by EAC and were not separate legal entities. In addition to employee payroll-related expenses, EAC incurred general and administrative (“G&A”) expenses related to leasing office space and other corporate overhead expenses during the period these properties were wholly owned by EAC. A portion of the consolidated G&A expenses reported for EAC were allocated to the Partnership 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.
     EAC (through its subsidiaries) contributed $93.7 million to the Partnership in March 2007. These proceeds were used by the Partnership, along with proceeds from the borrowings under the Partnership’s long-term debt agreements, to purchase the Elk Basin Assets. Additionally, EAC (through its subsidiaries) 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 14. Subsequent Events
     On May 1, 2008, the Partnership acquired an existing net profits interest in certain of its properties in the Permian Basin of West Texas in exchange for 283,700 common units representing limited partner interests in the Partnership. The issued units were valued at approximately $5.8 million.
     On May 5, 2008, the board of directors of the General Partner approved a new distribution methodology, which returns additional cash flow to the Partnership’s unitholders during high commodity price environments. The Partnership will distribute to unitholders 50 percent of the excess distributable cash flow above: (1) maintenance capital requirements; (2) an implied minimum quarterly distribution of $1.73 per unit annually, or $0.4325 per unit quarterly; and (3) a minimum coverage ratio of 1.10.
     On May 5, 2008, the board of directors of the General Partner declared a distribution for the first quarter of 2008 to unitholders of record as of the close of business on May 9, 2008. Approximately $19.2 million will be paid on or about May 15, 2008 to unitholders at a rate of $0.5755 per unit.

17


Table of Contents

ENCORE ENERGY PARTNERS LP
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
     The following discussion and analysis contains forward-looking statements, which give our current expectations or forecasts of future events. Actual results could differ materially from those discussed in these forward-looking statements due to many factors, including, but not limited to, those set forth under “Item 1A. Risk Factors” in our 2007 Annual Report on Form 10-K. The following discussion and analysis should be read in conjunction with the consolidated financial statements and notes thereto included in “Item 1. Financial Statements” of this Report and in “Item 8. Financial Statements and Supplementary Data” of our 2007 Annual Report on Form 10-K.
Introduction
     In this management’s discussion and analysis of financial condition and results of operations, the following will be discussed and analyzed:
    Overview of Business
 
    Results of Operations
 
      - Comparison of Quarter Ended March 31, 2008 to Quarter Ended March 31, 2007
 
    Liquidity and Capital Resources
 
    Capital Commitments and Contingencies
 
    Critical Accounting Policies and Estimates
 
    New Accounting Pronouncements
Overview of Business
     We are a growth-oriented Delaware limited partnership formed on February 13, 2007 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 assets consist primarily of producing and non-producing oil and natural gas properties in the Big Horn Basin of Wyoming and Montana, the Permian Basin of West Texas, and the Williston Basin of North Dakota.
     On September 17, 2007, we completed our IPO. Upon the closing of the IPO, Encore Operating contributed the Permian Basin Assets to us. The Permian Basin Assets are considered our predecessor and our historical results of operations include the results of operations of the Permian Basin Assets for all periods presented, whereas the results of operations of the Elk Basin Assets are only included from the date of acquisition. In February 2008, we completed the acquisition of the Permian and Williston Basin Assets from Encore Operating. Because the Permian and Williston Basin Assets were acquired from an affiliate, the acquisition was accounted for as a transaction between entities under common control, similar to a pooling, whereby the assets and liabilities were recorded at EAC’s historical cost and our historical financial information was recast to include the acquired properties for all periods presented. Accordingly, the consolidated financial statements and notes reflect the combined historical results of the Partnership, the Permian Basin Assets, and the Permian and Williston Basin Assets throughout the periods presented. These results are not indicative of our future results and our future results could differ materially from our historical results.

18


Table of Contents

ENCORE ENERGY PARTNERS LP
Results of Operations
Comparison of Quarter Ended March 31, 2008 to Quarter Ended March 31, 2007
     Oil and natural gas revenues. The following table illustrates the primary components of our oil and natural gas revenues for the periods indicated, as well as each period’s respective production volumes and average prices:
                                 
    Three months ended March 31,     Increase / (Decrease)  
    2008     2007     $     %  
Revenues (in thousands):
                               
Oil
  $ 37,195     $ 8,160     $ 29,035          
Natural gas
    7,002       4,613       2,389          
 
                         
Total combined oil and natural gas revenues
  $ 44,197     $ 12,773     $ 31,424       246 %
 
                         
 
                               
Average realized prices:
                               
Oil ($/Bbl)
  $ 87.30     $ 46.84     $ 40.46       86 %
Natural gas ($/Mcf)
  $ 7.88     $ 6.93     $ 0.95       14 %
Combined ($/BOE)
  $ 76.99     $ 44.80     $ 32.19       72 %
 
                               
Total production volumes:
                               
Oil (MBbls)
    426       174       252       145 %
Natural gas (MMcf)
    888       665       223       33 %
Combined (MBOE)
    574       285       289       101 %
 
                               
Average daily production volumes:
                               
Oil (Bbls/D)
    4,682       4,089       593       15 %
Natural gas (Mcf/D)
    9,760       7,881       1,879       24 %
Combined (BOE/D)
    6,309       5,402       907       17 %
 
                               
Average NYMEX prices:
                               
Oil (per Bbl)
  $ 97.74     $ 58.33     $ 39.41       68 %
Natural gas (per Mcf)
  $ 8.02     $ 6.77     $ 1.25       18 %
     Oil revenues increased $29.0 million from $8.2 million in the first quarter of 2007 to $37.2 million in the first quarter of 2008 primarily as a result of an increase in average realized oil prices, which contributed approximately $17.2 million in additional oil revenues, and an increase in oil production volumes of 252 MBbls, which increased oil revenues by approximately $11.8 million. Our average realized oil price increased $40.46 per Bbl as a result of increases in the overall market price for oil, as reflected in the increase in the average NYMEX price from $58.33 per Bbl in the first quarter of 2007 to $97.74 per Bbl in the first quarter of 2008. The increase in oil production volumes was primarily due to a full quarter of production from our Elk Basin Assets in the first quarter of 2008. For the first quarter of 2008, approximately 76 percent of our oil production was from our Elk Basin Assets. As the Elk Basin Assets were purchased in March 2007, only one month of oil production is included in the first quarter of 2007.
     Natural gas revenues increased $2.4 million from $4.6 million in the first quarter of 2007 to $7.0 million in the first quarter of 2008 primarily as a result of an increase in production volumes of 223 MMcf, which contributed approximately $1.5 million in additional natural gas revenues, and an increase in average realized natural gas prices, which increased natural gas revenues by approximately $0.9 million. The increase in natural gas production volumes was primarily due to an increase in production from operated properties in the first quarter of 2008 as a result of wells drilled during the second half of 2007. Our average realized natural gas price increased as a result of increases in the overall market price for natural gas, as reflected in the increase in the average NYMEX price from $6.77 per Mcf in the first quarter of 2007 to $8.02 per Mcf in the first quarter of 2008.

19


Table of Contents

ENCORE ENERGY PARTNERS LP
     The table below illustrates the relationship between our 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.
                 
    Three months ended March 31,
    2008   2007
Average realized oil price ($/Bbl)
  $ 87.30     $ 46.84  
Average NYMEX ($/Bbl)
  $ 97.74     $ 58.33  
Differential to NYMEX
  $ (10.44 )   $ (11.49 )
Average realized oil price to NYMEX percentage
    89 %     80 %
 
               
Average realized natural gas price ($/Mcf)
  $ 7.88     $ 6.93  
Average NYMEX ($/Mcf)
  $ 8.02     $ 6.77  
Differential to NYMEX
  $ (0.14 )   $ 0.16  
Average realized natural gas price to NYMEX percentage
    98 %     102 %
     In the first quarter of 2008, our average realized oil price as a percentage of the average NYMEX price improved to 89 percent from 80 percent in the first quarter of 2007. The differential tightened as a result of improved pricing in the Rocky Mountain area. We expect our oil differentials to remain flat in the second quarter of 2008 as compared to the first quarter of 2008.
     Our average realized natural gas price as a percentage of the average NYMEX price decreased to 98 percent in the first quarter of 2008 from 102 percent in the first quarter of 2007. We expect our natural gas differentials to remain flat in the second quarter of 2008 as compared to the first quarter of 2008.
     Marketing revenues and expenses. In March 2007, we acquired the Clearfork crude oil pipeline and the Wildhorse natural gas pipeline as part of the Elk 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, we collect pipeline tariffs for transportation through our Clearfork crude oil pipeline.
     The following table summarizes our marketing activities for the periods indicated:
                 
    Three Months Ended March 31,  
    2008     2007  
    (in thousands, except per BOE amounts)  
Marketing revenues
  $ 2,859     $ 1,238  
Marketing expenses
    (2,393 )     (1,080 )
 
           
 
               
Marketing, net
  $ 466     $ 158  
 
           
 
Marketing revenues per BOE
  $ 4.98     $ 4.34  
Marketing expenses per BOE
    (4.17 )     (3.79 )
 
           
 
               
Marketing gain, net per BOE
  $ 0.81     $ 0.55  
 
           

20


Table of Contents

ENCORE ENERGY PARTNERS LP
     Expenses. The following table summarizes our expenses, excluding marketing expenses shown above, for the periods indicated:
                                 
    Three months ended March 31,     Increase / (Decrease)  
    2008     2007     $     %  
Expenses (in thousands):
                               
Production:
                               
Lease operations
  $ 6,058     $ 2,691     $ 3,367          
Production, ad valorem, and severance taxes
    4,798       1,475       3,323          
 
                         
Total production expenses
    10,856       4,166       6,690       161 %
Other:
                               
Depletion, depreciation, and amortization
    9,120       3,706       5,414          
Exploration
    29       31       (2 )        
General and administrative
    2,922       555       2,367          
Derivative fair value loss
    15,587       3,683       11,904          
Other operating
    351       145       206          
 
                         
Total operating
    38,865       12,286       26,579       216 %
Interest
    1,640       1,102       538          
Income tax provision
    90       32       58          
 
                         
Total expenses
  $ 40,595     $ 13,420     $ 27,175       202 %
 
                         
 
                               
Expenses (per BOE):
                               
Production:
                               
Lease operations
  $ 10.55     $ 9.44     $ 1.11          
Production, ad valorem, and severance taxes
    8.36       5.17       3.19          
 
                         
Total production expenses
    18.91       14.61       4.30       29 %
Other:
                               
Depletion, depreciation, and amortization
    15.89       13.00       2.89          
General and administrative
    5.09       1.95       3.14          
Exploration
    0.05       0.11       (0.06 )        
Derivative fair value loss
    27.15       12.92       14.23          
Other operating
    0.61       0.51       0.10          
 
                         
Total operating
    67.70       43.10       24.60       57 %
Interest
    2.86       3.87       (1.01 )        
Income tax provision
    0.16       0.11       0.05          
 
                         
Total expenses
  $ 70.72     $ 47.08     $ 23.64       50 %
 
                         
     Production expenses. Total production expenses increased $6.7 million from $4.2 million in the first quarter of 2007 to $10.9 million in the first quarter of 2008 as a result of an increase in total production volumes and a $4.30 increase in production expenses per BOE. Our production margin for the first quarter of 2008 increased by $24.7 million (287 percent) to $33.3 million as compared to $8.6 million for the first quarter of 2007. On a per BOE basis, our production margin increased 92 percent to $58.08 per BOE as compared to $30.19 per BOE for the first quarter of 2007. Total oil and natural gas revenues per BOE increased by 72 percent while total production expenses per BOE increased by only 29 percent.
     Production expense attributable to LOE increased $3.4 million from $2.7 million in the first quarter of 2007 to $6.1 million in the first quarter of 2008, primarily due to an increase in production volumes, which contributed approximately $2.7 million of additional LOE, as well as a $1.11 increase in the average LOE per BOE rate, which contributed approximately $0.7 million in additional LOE. The increase in our average LOE per BOE rate was attributable to higher rates per BOE for the Elk Basin Assets as compared to our other properties.
     Production expense attributable to production, ad valorem, and severance taxes (“production taxes”) increased $3.3 million from $1.5 million in the first quarter of 2007 to $4.8 million in the first quarter of 2008 primarily due to increased revenues. As a percentage of oil and natural gas revenues, production taxes decreased to 10.9 percent in the first quarter of 2008 as compared to 11.5 percent in the first quarter of 2007.

21


Table of Contents

ENCORE ENERGY PARTNERS LP
     Depletion, depreciation, and amortization (“DD&A”) expense. DD&A expense increased $5.4 million from $3.7 million in the first quarter of 2007 to $9.1 million in the first quarter of 2008 as a result of increased production volumes, which contributed approximately $3.8 million of additional DD&A expense, and an increase of $2.89 in the per BOE rate, which contributed approximately $1.6 million of additional DD&A expense. The increase in our average DD&A per BOE rate was attributable to the higher acquisition price of the proved reserves of our Elk Basin Assets (acquired in March 2007) and the Williston Basin properties (acquired by EAC in April 2007) included in our Permian and Williston Basin Assets as compared to our Permian Basin Assets, which were acquired by EAC when oil and natural gas commodity prices were significantly lower.
     G&A expense. G&A expense increased $2.4 million from $0.5 million in the first quarter of 2007 to $2.9 million in the first quarter of 2008 primarily due to compensation expense recognized for management incentive units during the first quarter 2008, increased production volumes resulting in increased administrative fees due to Encore Operating pursuant to the Administrative Services Agreement, and expenses incurred associated with being a publicly traded partnership. During the first quarter of 2008, we recognized compensation expense of $1.1 million related to management incentive units, $1.0 million of expense per the Administrative Services Agreement, and $0.7 million of expenses related to being a publicly traded partnership.
     Derivative fair value loss. During the first quarter of 2008, we recorded a $15.6 million derivative fair value loss as compared to $3.7 million in the first quarter of 2007, the components of which were as follows:
                         
    Three months ended March 31,     Increase /  
    2008     2007     (Decrease)  
    (in thousands)  
Mark-to-market loss on commodity derivative contracts
  $ 14,002     $ 3,683     $ 10,319  
Premium amortization
    2,137             2,137  
Change in fair value of interest rate swap agreements prior to designation
    (381 )           (381 )
Settlements on commodity derivative contracts
    (171 )           (171 )
 
                 
Total derivative fair value loss
  $ 15,587     $ 3,683     $ 11,904  
 
                 
     Interest expense. Interest expense increased $0.5 million from $1.1 million in the first quarter of 2007 to $1.6 million in the first quarter of 2008 primarily as a result of additional borrowings under our revolving credit facility in February 2008 to fund the cash portion of the purchase price of the Permian and Williston Basin Assets. In addition, we did not have any debt prior to March 2007, when we borrowed under our revolving credit facility and a subordinated credit agreement to fund our acquisition of the Elk Basin Assets. All interest expense incurred during the first quarter of 2008 related to our revolving credit facility. Of the $1.1 million total interest expense in the first quarter of 2007, $0.6 million related to our revolving credit facility and $0.5 million related to our subordinated credit agreement. The weighted average interest rate for all long-term debt for the first quarter of 2008 was 5.5 percent as compared to 6.9 percent for the first quarter of 2007.
Liquidity and Capital Resources
     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 level of capital expenditures. We may use other sources of capital, including the issuance of additional debt or common units, to fund acquisitions and to maintain our financial flexibility.
     Our partnership agreement requires that we distribute all of our available cash quarterly. In May 2008, the board of directors of our general partner approved a new distribution methodology, which returns additional cash flow to our unitholders during high commodity price environments. We will distribute to unitholders 50 percent of the excess distributable cash flow above: (1) maintenance capital requirements; (2) an implied minimum quarterly distribution of $1.73 per unit annually, or $0.4325 per unit quarterly; and (3) a minimum coverage ratio of 1.10.
     Our partnership agreement allows our general partner to borrow funds to make distributions. We mitigate the price risk on a substantial portion of our production using commodity derivative contracts. We are generally required to settle our commodity derivatives within 5 days of the end of the month. As is typical in the oil and natural gas business, we do not generally receive the proceeds from the sale of production until 60 days following the end of the month. As a result, when oil and natural gas prices increase and are above the prices fixed in our commodity derivative contracts, we are required to pay the counterparty the difference between the fixed price and the market price before we receive the proceeds from the sale of production under the commodity derivative contracts. If this were to occur, we may make working capital borrowings to fund our distributions.

22


Table of Contents

ENCORE ENERGY PARTNERS LP
Because we distribute all of our available cash, we do not have those funds available to reinvest in our business to increase our reserves and production.
     We plan to make substantial capital expenditures in the future for the acquisition, exploitation, and development of oil and natural gas properties. We intend to finance these capital expenditures with cash flows from operations. We intend to finance our acquisition and future development and exploitation activities with a combination of cash flows from operations and issuances of debt, equity, or a combination of the two.
Cash Flows
     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 commodity prices. Realized oil and natural gas prices for the three months ended March 31, 2008 increased by 86 percent and 14 percent, respectively, as compared to same period of 2007. These prices fluctuate widely in response to changing market forces. For the three months ended March 31, 2008, approximately 74 percent of our production was oil. To the extent oil and natural gas prices decline or we experience a significant widening of our differentials, our earnings, cash flows from operations, and availability under our revolving credit facility may be adversely impacted. Prolonged periods of low oil and natural gas prices or sustained wide differentials could cause us to not be in compliance with financial covenants under our revolving credit facility and thereby affect our liquidity. We believe that our internally generated cash flows and availability under our revolving credit facility will be sufficient to fund our planned capital expenditures and distributions for the foreseeable future.
     Cash flows from operating activities. Cash provided by operating activities increased $20.0 million from $2.9 million for the first quarter of 2007 to $22.9 million for the first quarter of 2008, primarily due to an increase in our production margin.
     Cash flows from investing activities. Cash used in investing activities decreased $324.7 million from $329.7 million for the first quarter of 2007 to $5.0 million for the first quarter of 2008. During the first quarter of 2007, we purchased our Elk Basin Assets for approximately $328.4 million.
     Cash flows from financing activities. Cash flows from financing activities consists primarily of proceeds from and payments on long-term debt and distributions to unitholders. We periodically draw on our revolving credit facility to fund acquisitions and other capital commitments.
     During the first quarter of 2008, we used net cash of $17.9 million in financing activities as a result of $125.4 million in distributions to affiliates in connection with our acquisition of the Permian and Williston Basin Assets and $9.8 million in distributions to unitholders, offset by net borrowings of $117.3 million under our revolving credit facility. Net borrowings on our revolving credit facility resulted in a net increase in outstanding borrowings under our revolving credit facility from $47.5 million at December 31, 2007 to $165 million at March 31, 2008.
     During the first quarter of 2007, we received net cash of $327.3 million from financing activities, including net borrowings on our revolving credit facility and subordinated term loan of $237.5 million and contributions from EAC of $93.7 million used to finance the acquisition of the Elk Basin Assets.
Revolving Credit Facility
     Our principal source of short-term liquidity is our revolving credit facility.
     In conjunction with the closing of the acquisition of the Elk Basin Assets on March 7, 2007, OLLC entered into a five-year credit agreement with a bank syndicate comprised of Bank of America, N.A. and other lenders. The 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 credit agreement is $300 million. Availability under the credit agreement is subject to a borrowing base, which is redetermined semi-annually and upon requested special redeterminations. At March 31, 2008, the borrowing base was $240 million.

23


Table of Contents

ENCORE ENERGY PARTNERS LP
     The credit agreement matures on March 7, 2012. OLLC’s obligations under the credit agreement are secured by a first-priority security interest in OLLC’s and its restricted subsidiaries’ proved oil and natural gas reserves and in the equity interests of OLLC and its restricted subsidiaries. In addition, OLLC’s obligations under the credit agreement are guaranteed by us and OLLC’s restricted subsidiaries. Obligations under the credit agreement are non-recourse to EAC and its restricted subsidiaries.
     Loans under the credit agreement are subject to varying rates of interest based on (i) the total amount outstanding in relation to the borrowing base and (ii) 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 Total Outstanding Borrowings to Borrowing Base   Eurodollar Loans   Base Rate Loans
Less than .50 to 1
    1.000 %     0.000 %
Greater than or equal to .50 to 1 but less than .75 to 1
    1.250 %     0.000 %
Greater than or equal to .75 to 1 but less than .90 to 1
    1.500 %     0.250 %
Greater than or equal to .90 to 1
    1.750 %     0.500 %
     The “Eurodollar rate” for any interest period (either one, two, three, or six months, as selected by OLLC) is the rate per year equal to LIBOR, as published by Reuters or another source designated by Bank of America, N.A., for deposits in dollars for a similar interest period. The “base rate” is calculated as the higher of (i) the annual rate of interest announced by Bank of America, N.A. as its “prime rate” and (ii) the federal funds effective rate plus 0.5 percent.
     Any outstanding letters of credit reduce the availability under the credit agreement. Borrowings under the credit agreement may be repaid from time to time without penalty.
     The credit agreement, as amended on August 22, 2007, contains covenants that include, among others:
    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 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 OLLC maintain a ratio of consolidated current assets to consolidated current liabilities of not less than 1.0 to 1.0;
 
    a requirement that OLLC maintain a ratio of consolidated EBITDA (as defined in the credit agreement) to the sum of consolidated net interest expense plus letter of credit fees of not less than 1.5 to 1.0;
 
    a requirement that OLLC maintain a ratio of consolidated EBITDA (as defined in the credit agreement) to consolidated senior interest expense of not less than 2.5 to 1.0; and
 
    a requirement that OLLC maintain a ratio of consolidated funded debt (excluding certain related party debt) to consolidated adjusted EBITDA (as defined in the credit agreement) of not more than 3.5 to 1.0.
     The credit agreement contains customary events of default. 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 credit agreement to be immediately due and payable. At March 31, 2008, we were in compliance with all of our debt covenants.

24


Table of Contents

ENCORE ENERGY PARTNERS LP
     OLLC incurs a commitment fee on the unused portion of the credit agreement determined based on the ratio of amounts outstanding under the credit agreement to the borrowing base in effect on such date. The following table summarizes the calculation of the commitment fee under the credit agreement:
         
    Commitment
Ratio of Total Outstanding Borrowings to Borrowing Base   Fee Percentage
Less than .50 to 1
    0.250 %
Greater than or equal to .50 to 1 but less than .75 to 1
    0.300 %
Greater than or equal to .75 to 1 but less than .90 to 1
    0.375 %
Greater than or equal to .90 to 1
    0.375 %
     On March 31, 2008, we had $165 million of outstanding borrowings and $74.9 million available to borrow under our revolving credit facility. On May 2, 2008, we had $160 million outstanding and $79.9 million available to borrow under our revolving credit facility. As of March 31, 2008 and May 2, 2008, we had $0.1 million outstanding letters of credit.
     Current capitalization. At March 31, 2008, we had total assets of $484.9 million and total capitalization was $428.8 million, of which 62 percent was represented by partners’ equity and 38 percent by long-term debt. At December 31, 2007, we had total assets of $497.7 million and total capitalization was $442.5 million, of which 89 percent was represented by partners’ equity and 11 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 are used to finance future capital projects or potential acquisitions.
Capital Commitments and Contingencies
Capital Commitments
     Our primary needs for cash are as follows:
    Distributions to unitholders;
 
    Development, exploitation, and exploration of oil and natural gas properties;
 
    Acquisitions of oil and natural gas properties;
 
    Funding of necessary 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 the first quarter of 2008, we distributed $9.8 million to our unitholders with respect to the quarter ended December 31, 2007 at a rate of $0.3875 per unit.
     On May 5, 2008, the board of directors of our general partner declared a distribution with respect to the first quarter of 2008 to unitholders of record as of the close of business on May 9, 2008. The $19.2 million total distribution will be paid to unitholders on or about May 15, 2008 at a rate of $0.5755 per unit.
     Development, exploitation, and exploration of oil and natural gas properties. The following table summarizes our costs incurred (excluding asset retirement obligations) related to development, exploitation, and exploration activities during the periods indicated:
                 
    Three months ended March 31,  
    2008     2007  
    (in thousands)  
Development and exploitation
  $ 5,849     $ 3,675  
Exploration
    9       30  
 
           
Total
  $ 5,858     $ 3,705  
 
           

25


Table of Contents

ENCORE ENERGY PARTNERS LP
     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 the first quarter of 2008 yielded 25 gross (6.9 net) successful wells.
     Our exploration expenditures primarily relate to seismic costs, delay rentals, and geological and geophysical costs.
     Acquisitions of oil and natural gas properties. On February 7, 2008, we acquired the Permian and Williston Basin Assets for total consideration of approximately $125.4 million in cash, including certain closing adjustments, and 6,884,776 common units representing limited partner interests in us.
     On March 7, 2007, we acquired oil and natural gas properties in the Big Horn Basin, primarily in the Elk Basin field, for a purchase price of approximately $330.7 million, including $1.1 million of transaction costs.
     Funding of necessary working capital. At March 31, 2008, our working capital (defined as total current assets less total current liabilities) was $2.9 million, which remained consistent with our working capital of $2.8 million at December 31, 2007. Our production volumes, commodity prices, and differentials will be the largest variables affecting our working capital. We anticipate cash reserves to be close to zero because we intend to use any excess cash to fund capital obligations and reduce outstanding borrowings under our revolving credit facility. Our operating cash flow is determined in large part by production volumes and commodity prices. Assuming relatively stable commodity prices and constant or increasing production volumes, our operating cash flow should remain positive for the remainder of 2008.
     Off-balance sheet arrangements. We do not have any off-balance sheet arrangements that are material to our financial position or results of operations.
     Contractual obligations. The following table illustrates our contractual obligations and commitments outstanding at March 31, 2008:
                                         
    Payments Due by Period  
            Nine Months Ending                    
Contractual Obligations and   Total     December 31, 2008     2009 - 20010     2011 - 2012     Thereafter  
Commitments   (in thousands)  
Revolving credit facility (a)
  $ 196,601     $ 6,051     $ 16,137     $ 174,413     $  
Commodity derivative contracts (b)
    16,104       278       9,910       5,916        
Interest rate swap agreements
    1,222       351       871              
Development commitments (c)
    4,339       4,339                    
Asset retirement obligations (d)
    32,595       217       580       580       31,218  
 
                             
Total
  $ 250,861     $ 11,236     $ 27,498     $ 180,909     $ 31,218  
 
                             
 
(a)   Amounts include principal and projected interest payments. Please read Note 8 of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for additional information regarding our long-term debt.
 
(b)   Represents net liabilities for commodity derivative contracts that were valued as of March 31, 2008, the ultimate settlement of which are unknown because they are subject to continuing market risk. Please read “Item 3. Quantitative and Qualitative Disclosures about Market Risk” and Note 5 of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for additional information regarding our commodity derivative contracts.
 
(c)   Development commitments represent authorized purchases for work in process. Also at March 31, 2008, we had $7.5 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.
 
(d)   Asset retirement obligations represent the undiscounted future plugging and abandonment expenses on oil and natural gas properties and related facilities disposal at the completion of field life. Please read Note 7 of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for additional information regarding our asset retirement obligations.
     Other contingencies and commitments. We entered into an amended and restated administrative services agreement with Encore Operating, pursuant to which Encore Operating performs administrative services for us, such as accounting, corporate development, finance, land, legal, and engineering. Under the amended and restated administrative services agreement, Encore Operating initially received an administrative fee of $1.75 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. We also pay our share of expenses that are directly chargeable to wells under joint operating

26


Table of Contents

ENCORE ENERGY PARTNERS LP
agreements. 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. Effective April 1, 2008, the administrative fee paid to Encore Operating under the amended and restated administrative services agreement increased to $1.84 per BOE of our production as a result of the COPAS Wage Index Adjustment for the current year.
     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 the current year;
 
    if we or one of our subsidiaries acquires 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 our General Partner upon the recommendation of the conflicts committee of our General Partner; and
 
    otherwise as agreed upon by Encore Operating and our General Partner, with the approval of the conflicts committee of our General Partner.
Critical Accounting Policies and Estimates
     Please read “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Critical Accounting Policies and Estimates” in our 2007 Annual Report on Form 10-K for more information regarding our critical accounting policies and estimates.
New Accounting Pronouncements
     The effects of new accounting pronouncements are discussed in Note 2 of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements.”
Item 3. Quantitative and Qualitative Disclosures About Market Risk
     The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil and natural gas prices and interest rates. The disclosures are not meant to be precise indicators of potential exposure, but rather indicators of potential exposure. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for purposes other than speculative trading.
     The information included in “Item 7A. Quantitative and Qualitative Disclosures about Market Risk” in our 2007 Annual Report on Form 10-K is incorporated herein by reference. Such information includes a description of our potential exposure to market risks, including commodity price risk and interest rate risk.
Commodity Price Sensitivity
     Our outstanding commodity derivative contracts as of March 31, 2008 are discussed in Note 5 of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements.” As of March 31, 2008, the fair market value of our oil and natural gas derivative contracts was a net liability of $10.4 million and $0.2 million, respectively. Based on our open commodity derivative positions at March 31, 2008, a $1.00 increase in the respective NYMEX prices for oil and natural gas would increase our net derivative fair value liability by approximately $5.1 million, while a $1.00 decrease in the respective NYMEX prices for oil and natural gas would decrease our net derivative fair value liability by approximately $5.3 million.
Interest Rate Sensitivity
     At March 31, 2008, we had total long-term debt of $165 million, all of which was outstanding under our revolving credit facility. Our revolving credit facility is subject to floating market rates of interest that are linked to LIBOR. At this level of floating rate debt, if LIBOR increased one percent, we would incur an additional $1.7 million of interest expense per year, and if the rate decreased one percent, we would incur $1.7 million less.
     In the first quarter of 2008, as a result of the increase in debt levels resulting from the purchase of the Permian and Williston Basin Assets, we entered into interest rate swap agreements whereby we swapped $100 million of floating rate debt to a weighted average fixed rate of 3.06 percent and an expected margin of 1.25 percent under our revolving credit facility. As of

27


Table of Contents

ENCORE ENERGY PARTNERS LP
March 31, 2008, the change in the unrealized loss on our interest rate swap agreements was approximately $1.6 million and is included in AOCL in our Consolidated Balance Sheet. As of March 31, 2008, the fair market value of our interest rate swap agreements was a net liability of $1.2 million. If LIBOR increased one percent, the fair value of our interest rate swap agreements at March 31, 2008 would be an asset of approximately $1.5 million, and if LIBOR decreased one percent, the liability would increase by approximately $2.7 million.
Item 4. Controls and Procedures
     In accordance with the Securities Exchange Act of 1934 (the “Exchange Act”) Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer of our General Partner, of the effectiveness of our disclosure controls and procedures as of March 31, 2008. 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 March 31, 2008 to ensure that information required to be disclosed in our reports filed or submitted 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.
     There were no changes in our internal control over financial reporting during the quarter ended March 31, 2008 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
     From time to time, we are a party to various legal proceedings in the ordinary course of business. We are not currently a party to any legal or governmental claims that management believes will have a material adverse effect on our results of operations or financial position.
Item 1A. Risk Factors
     In addition to the other information set forth in this Report, readers should carefully consider the factors discussed in Part I, “Item 1A. Risk Factors” in our 2007 Annual Report on Form 10-K, which could materially affect our business, financial condition, or results of operations. The risks described in our 2007 Annual Report on Form 10-K are not the only risks we face. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition, or results of operations.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
     In connection with the acquisition of an existing net profits interest in certain of our properties in Crockett County, Texas on May 1, 2008, we issued 283,700 common units representing limited partner interests in us to the limited partners of the seller. The issuance of the common units was exempt from registration under Section 4(2) of the Securities Act of 1933, as amended.
Item 6. Exhibits
Exhibits
     
 
   
3.1
  Certificate of Limited Partnership of Encore Energy Partners LP (incorporated by reference to Exhibit 3.1 to Form S-1 (File No. 333-142847) for Encore Energy Partners LP, 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 to Exhibit 3.1 to the 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 to Exhibit 3.1 to the Current Report on Form 8-K, filed with the SEC on April 18, 2008).

28


Table of Contents

ENCORE ENERGY PARTNERS LP
     
 
   
10.1
  Purchase and Investment Agreement, dated December 27, 2007, by and among Encore Energy Partners LP, Encore Energy Partners Operating LLC, and Encore Operating, L.P. (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K, filed with the SEC on January 3, 2008).
 
   
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*
  Statement showing computation of ratio of earnings to fixed charges.
 
*   Filed herewith.

29


Table of Contents

ENCORE ENERGY PARTNERS LP
SIGNATURE
     Pursuant to the requirements 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:  May 8, 2008
  /s/ Andrea Hunter
 
   
 
  Andrea Hunter    
 
  Vice President, Controller, and Principal Accounting Officer    

30