10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

(Mark One)
þ	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the fiscal year ended December 31, 2007
or
o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the transition period from           to

Commission File Number:  001-33676

ENCORE ENERGY PARTNERS LP

(Exact name of registrant as specified in its charter)

Delaware	20-8456807
State or other jurisdiction of incorporation or organization	(I.R.S. Employer Identification No.)
777 Main Street, Suite 1400, Fort Worth, Texas 76102	76102
(Address of principal executive offices)	(Zip Code)

Registrant’s telephone number, including area code:(817) 877-9955

Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Name of each exchange on which registered
Common Units Representing Limited Partner Interests	New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

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

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o  No þ

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ  No o

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer o Accelerated filer o Non-accelerated filer þ
(Do not check if a smaller
reporting company)   Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Exchange Act Rule 12b-2). Yes o  No þ

The registrant’s common units were not publicly traded as of the last business day of the registrant’s most recently completed second fiscal quarter. The aggregate market value of common units held by non-affiliates of the registrant as of February 20, 2008 was $206,607,009 based on the last reported sales price of the units on the New York Stock Exchange on such date.

As of February 20, 2008, the registrant had 31,072,455 common units outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

None

ENCORE ENERGY PARTNERS LP

INDEX

		Page
PART I
Item 1.	Business		1
Item 1A.	Risk Factors		26
Item 1B.	Unresolved Staff Comments		45
Item 2.	Properties		45
Item 3.	Legal Proceedings		45
Item 4.	Submission of Matters to a Vote of Unitholders		45
PART II
Item 5.	Market for Registrant’s Common Units, Related Unitholder Matters and Issuer Purchases of Common Units		46
Item 6.	Selected Financial Data		48
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		51
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		74
Item 8.	Financial Statements and Supplementary Data		77
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure		110
Item 9A.	Controls and Procedures		110
Item 9B.	Other Information		110
PART III
Item 10.	Directors, Executive Officers and Corporate Governance		110
Item 11.	Executive Compensation		117
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters		129
Item 13.	Certain Relationships and Related Transactions, and Director Independence		131
Item 14.	Principal Accounting Fees and Services		135
PART IV
Item 15.	Exhibits, Financial Statement Schedules		136
	Signatures		138
Statement Showing Computation of Ratio of Earnings to Fixed Charges
Subsidiaries as of February 1, 2008
Consent of Ernst & Young LLP
Consent of Miller & Lents, Ltd.
Rule 13a-14(a)/15d-14(a) Certification
Rule 13a-14(a)/15d-14(a) Certification
Section 1350 Certification
Section 1350 Certification
Encore Energy Partners GP LLC Financial Statements

i

ENCORE ENERGY PARTNERS LP

GLOSSARY

The following are abbreviations and definitions of certain terms, including oil and natural gas industry terms, used in this annual report on Form 10-K (the “Report”). The definitions of proved developed reserves, proved reserves, and proved undeveloped reserves have been abbreviated from the applicable definitions contained in Rule 4-10(a)(2-4) of Regulation S-X.

•  Bbl.  One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.

•  Bbl/D.  One Bbl per day.

•  Bcf.  One billion cubic feet, used in reference to natural gas.

•  BOE.  One barrel of oil equivalent, calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Bbl of oil.

•  BOE/D.  One BOE per day.

•  Completion.  The installation of permanent equipment for the production of oil or natural gas.

•  Council of Petroleum Accountants Societies (“COPAS”).  A professional organization of oil and natural gas accountants that maintains consistency in accounting procedures and interpretations, including the procedures that are part of most joint operating agreements. These procedures establish a drilling rate and an overhead rate to reimburse the operator of a well for overhead costs, such as accounting and engineering.

•  Delay Rentals.  Fees paid to the lessor of an oil and natural gas lease during the primary term of the lease prior to the commencement of production from a well.

•  Developed Acreage.  The number of acres allocated or assignable to producing wells or wells capable of production.

•  Development Well.  A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

•  Dry Hole or Well.  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.

•  Farm-in or Farm-out.  An agreement where the owner of a working interest in an oil and natural gas lease assigns the working interest or a portion thereof to another party who desires to drill on the leased acreage. Generally, the assignee is required to drill one or more wells in order to earn its interest in the acreage. The assignor usually retains a royalty or reversionary interest in the lease. The interest received by an assignee is a “farm-in” while the interest transferred by the assignor is a “farm-out.”

•  Field.  An area consisting of a single reservoir of multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

•  Gross Acres or Gross Wells.  The total acres or wells, as the case may be, in which a working interest is owned.

ii

ENCORE ENERGY PARTNERS LP

•  Lease Operations Expense (“LOE”).  All direct and allocated indirect costs of producing oil and natural gas after completion of drilling and before removal of production from the property. 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.

•  MBOE/D.  One thousand BOE per day.

•  Mcf.  One thousand cubic feet, used in reference to natural gas.

•  Mcf/D.  One Mcf per day.

•  Mcfe.  One thousand cubic feet equivalent, calculated by converting oil to natural gas equivalent at a ratio of one Bbl of oil to six Mcf of natural gas.

•  Mcfe/D.  One Mcfe per day.

•  MMBbl.  One million Bbls.

•  MMBOE.  One million BOE.

•  MMcf.  One million cubic feet, used in reference to natural gas.

•  MMcf/D.  One MMcf per day.

•  MMcfe.  One million cubic feet equivalent, determined using the ratio of one Bbl of oil to six Mcf of natural gas.

•  MMcfe/D.  Once MMcfe per day.

•  Net Acres or Net Wells.  Gross acres or wells, as the case may be, multiplied by our working interest percentage.

•  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.

•  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.

•  NYMEX.  New York Mercantile Exchange.

•  Oil.  Crude oil, condensate, and NGLs.

•  Operator.  The entity responsible for the exploration, exploitation, and production of an oil or natural gas well or lease.

•  Present Value of Future Net Revenues (“PV-10”).  The pretax present value of estimated future revenues to be generated from the production of proved reserves, net of future LOE and development costs, using prices and costs as of the date of estimation without future escalation, without giving effect to derivative activities, non-property related expenses such as general and administrative expenses, debt service, depletion, depreciation, and amortization, and income taxes, discounted using an annual discount rate of 10 percent.

•  Production Margin.  Oil and natural gas revenues less LOE and production, ad valorem, and severance taxes.

iii

ENCORE ENERGY PARTNERS LP

•  Productive Well.  A producing well or well capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities.

•  Proved Developed Reserves.  Proved reserves that can be expected to be recovered from existing wells with existing equipment and operating methods.

•  Proved Reserves.  The estimated quantities of crude oil, natural gas, and NGLs that 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 to establish production. Proved undeveloped reserves include unrealized 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.

•  Royalty.  An interest in an oil and natural gas lease that gives the owner the right to receive a portion of the production from the leased acreage (or of the proceeds from the sale thereof), but does not require the owner to pay any portion of the 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.

•  SEC.  The United States Securities and Exchange Commission.

•  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.

•  Standardized Measure.  The present value of estimated future net revenue to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC (using prices and costs in effect as of the date of estimation), less future development, LOE, and income tax expenses, and discounted at 10 percent per annum to reflect the timing of future cash flows. Standardized Measure differs from PV-10 because Standardized Measure includes the effect of estimated future income taxes.

•  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.

•  Undeveloped Acreage.  Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas and oil regardless of whether such acreage contains proved reserves.

•  Unit.  A specifically defined area within which acreage is treated as a single consolidated lease for operations and for allocations of costs and benefits without regard to ownership of the acreage. Units are established for the purpose of recovering oil and natural gas from specified zones or formations.

•  Waterflood.  A secondary recovery operation in which water is injected into the producing formation in order to maintain reservoir pressure and force oil toward and into the producing wells.

iv

ENCORE ENERGY PARTNERS LP

•  Working Interest.  An interest in an oil or natural gas lease that gives the owner 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.

v

ENCORE ENERGY PARTNERS LP

This Report contains forward-looking statements, which give our current expectations and forecasts of future events. Please read “Item 1A. Risk Factors” for a description of various factors that could materially affect our ability to achieve the anticipated results described in the forward-looking statements. Certain terms commonly used in the oil and natural gas industry and in this Report are defined above under the caption “Glossary.” In addition, all production and reserve volumes disclosed in this Report represent amounts net to us.

PART I

ITEM 1.   BUSINESS

General

Our Business.  We are a growth-oriented Delaware limited partnership formed on February 13, 2007 by Encore Acquisition Company (“EAC”) to acquire, exploit, and develop oil and natural gas properties and to acquire, own, and operate related assets.

On September 17, 2007, we completed our initial public offering (“IPO”) of 9,000,000 common units, at a price to the public of $21.00 per unit. On October 11, 2007, the underwriters exercised their option to purchase an additional 1,148,400 common units. Net proceeds from the issuance of common units were approximately $193.5 million, after deducting the underwriters’ discount and a structuring fee of approximately $14.9 million, in the aggregate, and offering expenses of approximately $4.7 million.

At the time of our initial public offering in September 2007, our assets consisted primarily of the following:

•  Elk Basin Assets.  On March 7, 2007, we acquired oil and natural gas properties and related assets in the Elk Basin of Wyoming and Montana from subsidiaries of Anadarko Petroleum Corporation (“Anadarko”) for approximately $330.7 million, including estimated transaction costs of approximately $1.1 million.

•  Legacy Permian Basin Assets.  Our predecessor asset properties in the Permian Basin were acquired by EAC in March 2000 and are located in Crockett County, Texas.

The Legacy Permian Basin Assets are considered our predecessor. Therefore, our results of operations, reserve data, and other operating and financial information include the Legacy Permian Basin Assets for all periods presented. The Elk Basin Assets are included in our historical results of operations only from and after March 7, 2007.

On February 7, 2008, we acquired certain oil and natural gas producing properties and related assets in the Permian and Williston Basins from Encore Operating, L.P. (“Encore Operating”), a wholly owned subsidiary of EAC, in exchange for approximately $125.4 million in cash and 6,884,776 common units representing limited partner interests in us. The transaction had an effective date of January 1, 2008. The Permian and Williston Basin properties currently produce approximately 1,800 BOE/D. Our historical results of operations, reserve data, and other operating and financial information do not include any information regarding these properties, unless otherwise indicated.

Proved Reserves.  Our estimated total proved reserves at December 31, 2007 were 14.4 MMBbls of oil and 39.1 Bcf of natural gas, based on December 31, 2007 spot market prices of $96.01 per Bbl of oil and $7.47 per Mcf of natural gas. On a BOE basis, our proved reserves were 20.9 MMBOE at December 31, 2007, of which approximately 69 percent was oil and approximately 86 percent was classified as proved developed. Our average reserve-to-production ratio is approximately 13.5 years, based on our total proved reserves as of December 31, 2007 and annualized production for the fourth quarter 2007.

Drilling.  In 2007, we drilled 8 gross (5.8 net) operated productive wells and participated in drilling 12 gross (0.6 net) non-operated productive wells for a total of 20 gross (6.5 net) productive wells. In 2007, we

1

ENCORE ENERGY PARTNERS LP

did not drill any operated non-productive wells. In 2007, we participated in drilling 1 gross (0.5 net) non-operated non-productive well. We invested $8.9 million in development and exploitation activities in 2007.

Our Relationship with Encore Acquisition Company

One of our principal attributes is our relationship with EAC. We intend to use the significant experience of EAC’s management team to execute our growth strategy. EAC is a publicly traded oil and natural gas company engaged in the acquisition and development of oil and natural gas reserves from onshore fields in the United States. Since its inception in 1998, EAC has sought to acquire long-lived and mature producing properties that have predictable production decline profiles. EAC’s fields are further characterized by large accumulations of original oil in place. Original oil in place is not an indication of how much oil is likely to be produced, but it is an indication of the estimated size of a reservoir. We and EAC believe that many of EAC’s oil and natural gas properties are, or after additional capital is invested may become, well suited for our partnership.

While EAC believes it may be in its best interest to contribute or sell additional assets to us due to its significant ownership of limited and general partner interests in us, EAC constantly evaluates acquisitions and dispositions and may elect to acquire or dispose of oil and natural gas properties in the future without offering us the opportunity to purchase those assets. EAC has retained such flexibility because it believes it is in the best interests of its shareholders to do so. We cannot say with any certainty which, if any, opportunities to acquire assets from EAC may be made available to us or if we will choose to pursue any such opportunity. Moreover, EAC is not prohibited from competing with us and constantly evaluates acquisitions and dispositions that do not involve us.

2

ENCORE ENERGY PARTNERS LP

Organizational Structure

The following diagram depicts our organizational structure as of February 20, 2008:

(a) As of February 20, 2008, one management incentive unit represented 1.25 common unit equivalents. For additional discussion of the management incentive units, please read “Item 11. Executive Compensation — Compensation Discussion and Analysis — Management Incentive Units.”

3

ENCORE ENERGY PARTNERS LP

Business Strategy

Our primary business objective is to make quarterly cash distributions to our unitholders and, over time, increase our quarterly cash distributions. Our strategy for achieving this objective is to:

•  Purchase assets from EAC through negotiated transactions.  In February 2008, we acquired certain oil and natural gas properties directly from EAC, and we expect to have the opportunity to acquire additional oil and natural gas properties and midstream assets directly from EAC in the future. We will seek to acquire from EAC oil and natural gas properties with predictable production profiles, low decline rates, long reserve lives, and modest capital requirements. EAC has indicated that it intends to use us as a growth vehicle to pursue the acquisition of producing oil and natural gas properties and midstream assets. Because we are not subject to federal income taxation at the entity level, we believe that we have a lower cost of capital than EAC and our corporate competitors that enhances our ability to acquire oil and natural gas properties and midstream assets. If we purchase additional assets from EAC, we believe that we will do so in negotiated transactions and not through an auction process. Although EAC is not under any obligation to sell additional properties to us, we believe EAC will have a strong incentive to do so given its significant ownership of limited and general partner interests in us.

•  Purchase assets through joint efforts with EAC.  We expect to have the opportunity to participate with EAC in jointly pursuing oil and natural gas properties and midstream assets that may not be attractive acquisition candidates for either of us individually or that we would not be able to pursue on our own. For example, a package of oil and natural gas properties may include both long-lived assets with low-risk exploitation and development opportunities that would be of interest to us and upside opportunities requiring more capital that would be of interest to EAC. We intend to jointly pursue these and other acquisitions with EAC to the extent they would be well suited for our partnership. We believe this arrangement will provide us with a competitive advantage in the acquisition of oil and natural gas properties and midstream assets. Because we are not subject to federal income taxation at the entity level, we believe that we will have a lower cost of capital than our corporate competitors that could enhance our ability to acquire oil and natural gas properties.

•  Purchase assets independently of EAC.  Our growth strategy includes pursuing accretive acquisitions of oil and natural gas properties and midstream assets, and we intend to target longer-lived, low-decline reserves. Such reserves typically exhibit more sustainable production profiles, thereby better enabling us to grow reserves and production and increasing the likelihood that acquired assets will benefit from enhanced recovery techniques. In addition, we intend to seek to acquire large and mature oil and natural gas fields with opportunities for incremental improvements in hydrocarbon recovery through secondary and tertiary recovery techniques, which will offer us the most potential to increase efficiency, add value, and increase cash flows. We believe that we have a cost of capital advantage relative to our corporate competitors that enhances our ability to acquire oil and natural gas properties.

•  Use the benefits of our relationship with EAC and the leadership of I. Jon Brumley and Jon S. Brumley. EAC has a long history of pursuing and consummating acquisitions of oil and natural gas properties in North America. Through our relationship with EAC, we have access to a significant pool of management talent and strong industry relationships that we use in implementing our strategies. I. Jon Brumley, EAC’s founder and Chairman of the Board, and Jon S. Brumley, EAC’s Chief Executive Officer and President, are actively involved in our business.

•  Use EAC’s technical expertise to identify and implement successful exploitation techniques to achieve optimum production and reserve recovery.  Through our relationship with EAC, we have significant technical expertise in secondary and tertiary recovery methods, which differentiates us from many of our competitors. In order to be successful in achieving our primary objective of increasing our quarterly cash distributions to our unitholders over time, it is important that our production either remains relatively flat or increases over time. In order to ensure that our decline rate remains low, our budget must not have a large proportion of development drilling. New wells not associated with primary or

4

ENCORE ENERGY PARTNERS LP

secondary recovery often have a high initial decline rate. Therefore, with too large of a development budget, our decline rate may become higher than desirable. We intend to use EAC’s technical expertise to achieve optimum production and reserve recovery.

•  Mitigate negative effects of falling commodity prices through entering into commodity derivative contracts.  When appropriate, we enter into commodity derivative transactions with unaffiliated third parties in order to mitigate the effects of falling commodity prices. Our current hedging strategy is to enter into put contracts for approximately one-third of our forecasted production and fixed-price contracts (such as swaps or collars) for an additional one-third of our future production. Using this approach, we have a fixed price floor for two- thirds of our forecasted production, but a fixed ceiling price for only one-third of our forecasted production, which enables us to participate in commodity price increases for our oil and natural gas while protecting two-thirds of our future production if prices fall. We plan to maintain the flexibility to mitigate price risk on the remaining one-third of our future production or leave the production unmitigated from price risk for approximately 36 to 48 months, depending on various factors including commodity prices, budget requirements, and cash reserves.

•  Maintain relatively low levels of indebtedness over time and sufficient capacity under our revolving credit facility to permit us to be opportunistic with future acquisitions of oil and natural gas properties.  In the future, we expect to fund approximately 50 percent of the purchase price of acquisitions with the proceeds from equity issuances and cash flows from operations in order to maintain, over time, relatively low levels of indebtedness.

Competitive Strengths

We believe the following competitive strengths allow us to achieve our objectives of generating and growing cash available for distribution:

•  Our relationship with EAC.  We believe that our relationship with EAC provides us with certain advantages, including:

•  the ability to acquire assets directly from EAC;

•  the ability to acquire assets jointly with EAC;

•  the ability to use EAC’s technical expertise to identify and implement successful exploitation techniques to maximize production and reserve recovery;

•  strong commercial relationships throughout the oil and natural gas industry, including major oil companies; and

•  access to EAC’s broad operational, commercial, technical, risk management, and administrative infrastructure.

•  Our asset base is characterized by low-declining, stable, and long-lived production.  Our properties have well understood geologic features, predictable production profiles, and modest capital requirements that make them well suited to our objective of making regular cash distributions to our unitholders. We have identified an inventory of enhanced recovery projects, which we believe will enable us to maintain our current production levels from these assets for several years.

•  The Chairman of our general partner, I. Jon Brumley, and the Chief Executive Officer and President of our general partner, Jon S. Brumley, and EAC’s experienced management, operating, and technical teams share a long working history together and in the oil and natural gas industry.  Our general partner’s management team, which includes I. Jon Brumley and Jon S. Brumley, has a proven track record of enhancing value through the investment in and the acquisition, exploitation, and integration of oil and natural gas properties and related assets. The extensive experience and contacts of our general partner’s management team within the oil and natural gas industry provide a strong foundation and

5

ENCORE ENERGY PARTNERS LP

focus for managing and enhancing our operations, for accessing strategic acquisition opportunities, and for developing our assets.

•  Our ability to use EAC’s technical expertise, particularly in enhanced recovery methods, enables us to efficiently produce and maximize the profitability of our assets.  We believe EAC’s technical expertise in secondary and tertiary recovery methods is ideally suited to enhance the value of the core properties in our portfolio. Due to the mature nature of our assets and the significant amount of hydrocarbons in place, enhancing the recovery and improving the efficiency of the operations could add considerable value.

•  Our operational control of approximately 75 percent of our properties permits us to manage our operating costs and better control capital expenditures as well as the timing of development activities.  We operate properties representing approximately 75 percent of our proved reserves, which allows us to control capital allocation and expenses. For 2007, our direct operating expenses consisted of LOE of $10.20 per BOE and production, ad valorem, and severance taxes of $6.28 per BOE.

•  Our cost of capital, ability to issue additional common units, and capacity under our revolving credit facility enables us to be competitive in pursuing acquisitions.  Unlike our corporate competitors, we are not subject to federal income taxation at the entity level. We believe that this attribute provides us with a lower cost of capital, thereby enhancing our ability to compete for future acquisitions both individually and jointly with EAC. Our ability to issue additional common units in connection with acquisitions will enhance our financial flexibility. As of February 25, 2008, we had approximately $70.4 million available to borrow under our revolving credit facility. We believe these attributes enable us to be competitive in seeking to acquire oil and natural gas properties.

Operations

Well Operations

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

We were the operator of properties representing approximately 75 percent of our proved reserves at December 31, 2007. As operator, we are able to control expenses, capital allocation, and the timing of exploitation and development activities on our properties. We also own working interests in properties that are operated by third parties, and are required to pay our share of operating, exploitation, and development costs. During 2007, 2006, and 2005, our costs for development activities on non-operated properties were approximately $2.3 million, $1.0 million, and $1.6 million, respectively. We also own royalty interests in wells operated by third parties that are not burdened by LOE or capital costs; however, we have little control over the implementation of projects on these properties.

In connection with the completion of our IPO, we entered into an amended and restated administrative services agreement with Encore Operating and EAC. Pursuant to the administrative services agreement, Encore Operating provides administrative services to us, such as accounting, corporate development, finance, land, legal, and engineering. Encore Operating receives 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 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.

6

ENCORE ENERGY PARTNERS LP

The administrative fee will increase in the following circumstances:

•  beginning on the first day of April in each year beginning on April 1, 2008 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.

Natural Gas Gathering

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

•  realize faster connection of newly drilled wells to the existing system;

•  control pipeline operating pressures and capacity to maximize our production;

•  control compression costs and fuel use;

•  maintain system integrity;

•  control the monthly nominations on the receiving pipelines to prevent imbalances and penalties; and

•  track sales volumes and receipts closely to assure all production values are realized.

Our gas gathering systems are operated for us by Encore Operating pursuant to the administrative services agreement.

Seasonal Nature of Business

Seasonal weather conditions and lease stipulations can limit our development activities and other operations and, as a result, we seek to perform the majority of our development during the summer months. These seasonal anomalies can pose challenges for meeting our well development objectives and increase competition for equipment, supplies, and personnel during the spring and summer months, which could lead to shortages and increase costs or delay our operations.

7

ENCORE ENERGY PARTNERS LP

Production and Price History

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

	Year Ended December 31,
	2007			2006		2005
Total Production Volumes:
Oil (MBbls)		1,053			7		10
Natural gas (MMcf)		1,869			1,796		2,004
Combined (MBOE)		1,365			306		344
Average Daily Production Volumes:
Oil (Bbl/D)		3,440			18		28
Natural gas (Mcf/D)		5,272			4,920		5,490
Combined (BOE/D)		4,318			838		942
Average Realized Prices:
Oil (per Bbl)	$	55.85		$	62.18	$	53.29
Natural gas (per Mcf)		6.56			6.87		8.17
Combined (per BOE)		52.09			41.67		49.13
Average Costs per BOE:
Lease operations expense	$	10.20		$	5.47	$	5.09
Production, ad valorem, and severance taxes		6.28			4.01		4.28
Depletion, depreciation, and amortization		19.05			3.92		3.74
Derivative fair value loss		19.27			—		—
General and administrative		7.84			2.06		1.66
Other operating expense		0.56			0.80		0.76
Marketing, net		(1.40	)		—		—

Productive Wells

The following table sets forth information relating to the productive wells in which we owned a working interest as of December 31, 2007. Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which we had a working interest, regardless of our percentage interest. A net well is not a physical well, but is a concept that reflects the actual total working interest we held in all wells. The number of net wells we owned is calculated by totaling the percentage interests we held in all our gross wells.

8

ENCORE ENERGY PARTNERS LP

Our wells may produce both oil and natural gas. Wells are classified as oil or natural gas wells according to their predominant production stream. As of December 31, 2007, we owned a working interest in 650 gross wells. We also held royalty interests in units and acreage beyond the wells in which we have a working interest.

	Oil Wells							Natural Gas Wells
					Average							Average
	Gross		Net		Working			Gross		Net		Working
	Wells(a)		Wells		Interest			Wells(a)		Wells		Interest
Elk Basin
Operated		327		247		75	%		39		28		71	%
Permian Basin
Operated		—		—		—			52		28		54	%
Non-operated		—		—		—			232		54		23	%
Total		327		247		75	%		323		110		34	%

(a) At December 31, 2007, 4 of our wells had multiple completions.

Acreage

The following table sets forth information relating to our leasehold acreage at December 31, 2007. All of our oil and natural gas leases are held by production, which means that for as long as our wells continue to produce oil or natural gas, we will continue to own the lease.

	Gross Acreage		Net Acreage
Elk Basin:
Developed		16,770		13,424
Undeveloped		—		—
		16,770		13,424
Permian Basin:
Developed		22,387		8,948
Undeveloped		2,262		1,662
		24,649		10,610
Total:
Developed		39,157		22,372
Undeveloped		2,262		1,662
		41,419		24,034

9

ENCORE ENERGY PARTNERS LP

Development Results

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

The following table sets forth information with respect to wells completed during the periods indicated, regardless of when development was initiated. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled, quantities of reserves found, or economic value. No exploratory wells were drilled during the periods presented.

	Year Ended December 31,
	2007		2006		2005
Gross Development Wells:
Productive		20.0		3.0		18.0
Dry		1.0		—		1.0
Total		21.0		3.0		19.0
Net Development Wells:
Productive		6.5		1.4		2.6
Dry		0.5		—		0.1
Total		7.0		1.4		2.7

Present Activities

As of December 31, 2007, we had a total of 3 gross (2.5 net) wells that had reached total depth and were in varying stages of completion pending first production, all of which were development wells.

Delivery Commitments

We do not have any delivery commitments at prices other than market prices or for terms greater than one year.

Principal Customers and Marketing Arrangements

Our oil and natural gas production is principally sold to end users, marketers, processors, refiners, and other purchasers having access to nearby pipeline, processing, and gathering facilities. In areas where there is no practical access to pipelines, oil is trucked to central storage facilities where it is aggregated and sold to various local markets and downstream purchasers. Our production sales agreements contain customary terms and conditions for the oil and natural gas industry, provide for sales based on prevailing market prices in the area, and generally have terms ranging from 30 days to one year.

For 2007, our largest purchasers included Marathon Oil Corporation and ConocoPhillips, which accounted for 52 percent and 16 percent of our total sales of production, respectively. Our marketing of oil and natural gas can be affected by factors beyond our control, the potential effects of which cannot be accurately predicted. Management believes that the loss of any one purchaser would not have a material adverse effect on our ability to market our oil and natural gas production.

Our natural gas production and gathered natural gas from operated Permian Basin properties is generally sold on the spot market or under market-sensitive, short-term agreements with purchasers, including the marketing affiliates of intrastate and interstate pipelines, independent marketing companies, gas processing

10

ENCORE ENERGY PARTNERS LP

companies, and other purchasers who have the ability to pay the highest price for the natural gas production and move the natural gas under the most efficient and effective transportation agreements. Because all of our natural gas from operated Permian Basin properties is sold under market-priced agreements, we are positioned to take advantage of future increases in natural gas prices, but we are also subject to any future price declines. We do not market our own natural gas on our non-operated Permian Basin properties, but receive our share of revenues from the operator.

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

The difference between NYMEX market prices and the price received at the wellhead for oil and natural gas production is commonly referred to as a differential. We expect the differential between the NYMEX price of crude oil and the wellhead price we receive to tighten in the first quarter of 2008 as compared to the $25.26 per Bbl negative differential we realized in the fourth quarter of 2007 due to the acquisition of certain oil and natural gas producing properties and related assets in the Permian and Williston Basins from Encore Operating as discussed in “Properties — Recently Acquired Properties” below. Oil differentials in the fourth quarter 2007 were impacted by the quality of the crude oil in the Elk Basin area, which is a heavy, sour crude, as well as its location relative to markets in the Rocky Mountains. In recent years, continued production increases from competing Canadian and Rocky Mountain producers, in conjunction with limited refining and pipeline capacity in the Rocky Mountain area and corresponding steep pricing discounts by regional refiners, have gradually widened this differential. Natural gas differentials are expected to remain flat in the first quarter of 2008 as compared to the $0.22 per Mcf positive differential we realized in the fourth quarter of 2007. We cannot accurately predict future crude oil and natural gas differentials. Increases in the differential between the NYMEX price for oil and natural gas and the wellhead price we receive could have a material adverse effect on our results of operations, financial position, and cash flows. For analysis of our oil and natural gas differentials in 2007, 2006, and 2005, please read “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Competition

The oil and natural gas industry is highly competitive. We encounter strong competition from other independent operators and major oil companies in acquiring properties and contracting for development equipment. Many of these competitors have financial and technical resources substantially larger than ours. As a result, our competitors may be able to pay more for desirable leases, or to evaluate, bid for, and purchase a greater number of properties or prospects than our resources will permit.

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

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

11

ENCORE ENERGY PARTNERS LP

Properties

Nature of Our Ownership Interests

The following table sets forth the net production, proved reserve quantities, and PV-10 of our properties in our principal areas of operation as of and for the dates indicated:

										Proved Reserve Quantities
	2007 Net Production									at December 31, 2007									PV-10
			Natural									Natural							at December 31, 2007
	Oil		Gas		Total		Percent			Oil		Gas		Total		Percent			Amount(a)		Percent
	(MBbls)		(MMcf)		(MBOE)					(MBbls)		(MMcf)		(MBOE)					(In thousands)
Elk Basin		1,048		286		1,095		80	%		14,367		2,174		14,729		70	%	$	370,266		83	%
Permian Basin		6		1,583		270		20	%		50		36,966		6,211		30	%		73,869		17	%
Total		1,054		1,869		1,365		100	%		14,417		39,140		20,940		100	%	$	444,135		100	%

(a) Giving effect to commodity derivative contracts, our PV-10 would have been decreased by $6.9 million at December 31, 2007. Standardized Measure at December 31, 2007 was $438.4 million. Standardized Measure differs from PV-10 by $5.8 million because Standardized Measure includes the effect of future income taxes. Since we are taxed as a partnership that is not subject to federal income taxes, future income taxes reflect the impact of estimated future Texas margin taxes. Therefore, we believe PV-10 provides the best method for assessing our relative value.

The estimates of our proved oil and natural gas reserves are based on estimates prepared by Miller and Lents, Ltd. (“Miller and Lents”), independent petroleum engineers. Guidelines established by the SEC regarding the present value of future net revenues were used to prepare these reserve estimates. Oil and natural gas reserve engineering is and must be recognized as a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in any exact way, and estimates of other engineers might differ materially from those included herein. The accuracy of any reserve estimate is a function of the quality of available data and engineering, and estimates may justify revisions based on the results of drilling, testing, and production activities. Accordingly, estimates of reserves and their value are inherently imprecise and are subject to constant revision and change, and they should not be construed as representing the actual quantities of future production or cash flows to be realized from oil and natural gas properties or the fair market value of such properties.

12

ENCORE ENERGY PARTNERS LP

Our Areas of Operation

All of our properties are located in the Big Horn Basin of Wyoming and Montana and the Permian Basin of West Texas, which are mature producing regions with well known geologic characteristics. These properties are located within fields that exhibit long-lived production. Most of our properties have been producing for more than 32 years, and one field has been producing continuously for more than 62 years.

Elk Basin Properties

Our Elk Basin properties are located in the Big Horn Basin in northwestern Wyoming and south central Montana. The Big Horn Basin is formed by the Big Horn Mountains to the east, the Absaroka Mountains to the west, the Owl Creek Mountains to the south, and the Ny-Bowler Lineament to the north. The Big Horn Basin is located in Park County, Wyoming and Carbon County, Montana. The Big Horn Basin is characterized by oil and natural gas fields with long production histories and multiple producing formations. The Big Horn Basin is a prolific basin and has produced over 1.8 billion Bbls of oil since its discovery in 1906.

Our properties in the Elk Basin field, Northwest Elk Basin field, and the South Elk Basin field were acquired from subsidiaries of Anadarko in March 2007 for approximately $330.7 million, including transaction costs of approximately $1.1 million. The producing horizons in these fields are the Embar-Tensleep, Madison, Frontier, and Big Horn formations. From the date of acquisition through December 31, 2007, production from the Elk Basin Assets averaged approximately 3,580 BOE/D, of which approximately 96 percent was oil and 4 percent was natural gas. The Elk Basin Assets had estimated proved reserves at December 31, 2007 of 14,729 MBOE, of which 13,227 MBOE was proved developed and 1,502 MBOE was proved undeveloped. Approximately 94 percent of proved reserves of the Elk Basin Assets are located in the Elk Basin field.

13

ENCORE ENERGY PARTNERS LP

Our oil and natural gas properties in the Elk Basin area include 16,770 gross acres (13,424 net) located in Park County, Wyoming and Carbon County, Montana. During 2007, we drilled 6 gross (5.0 net) wells and invested approximately $3.9 million of capital to develop these properties. In addition, as of December 31, 2007, we had a total of 3 gross (2.5 net) wells in the Elk Basin area that had reached total depth and were in varying stages of completion pending first production, all of which were development wells. All of our production in the Elk Basin area is operated. Our Elk Basin properties have a production decline rate of approximately 8 percent per year and a reserve-to-production ratio of approximately 11.5 years, based on annualized production for the fourth quarter 2007.

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

The following map depicts the location of our oil and natural gas properties in the Elk Basin field.

Oil and Natural Gas Properties

Embar-Tensleep Formation in the Elk Basin Field.  Production in the Embar-Tensleep formation is currently being enhanced through a tertiary recovery technique involving effluent gas, or flue gas, from a natural gas processing facility located in the Elk Basin field. From 1949 to 1974, flue gas was injected into the Embar-Tensleep formation to increase pressure and improve production of resident hydrocarbons. Flue gas injection was re-established in 1998, and pressure monitoring wells indicate that the reservoir pressure continues to increase.

Our wells in the Embar-Tensleep formation of the Elk Basin field are drilled to a depth of 4,200 to 5,400 feet. We hold an average 62 percent working interest and an average 57 percent net revenue interest in these wells. At December 31, 2007, the Embar-Tensleep formation had estimated total proved reserves of 5,908 MBOE, all of which were oil and 96 percent of which were proved developed.

14

ENCORE ENERGY PARTNERS LP

Madison Formation in the Elk Basin Field.  Production in the Madison formation is being enhanced through a waterflood. We believe that we can enhance production in the Madison formation by, among other things, reestablishing optimal injection and producing well patterns.

Our wells in the Madison formation of the Elk Basin field are drilled to a depth of 4,800 to 5,800 feet. We hold an average 67 percent working interest and an average 62 percent net revenue interest in our wells in these wells. The Madison formation had estimated total proved reserves at December 31, 2007 of 6,442 MBOE, all of which were oil and 86 percent of which were proved developed.

Frontier Formation in the Elk Basin Field.  The Frontier formation is being produced through primary recovery techniques. Our wells in the Frontier formation of the Elk Basin field are typically drilled to a depth of 1,600 to 2,900 feet. We hold an average 96 percent working interest and an average 83 percent net revenue interest in our wells in the Frontier formation.

The Frontier formation had estimated total proved reserves at December 31, 2007 of 1,303 MBOE, 77 percent of which were oil and 71 percent of which were proved developed.

Other Oil and Natural Gas Properties.  We also operate wells in the Big Horn, Embar-Tensleep, and Madison formations in the Northwest Elk Basin field and in the Embar-Tensleep, Middle Frontier, Torchlight, and Peay Sand formations in the South Elk Basin field. We hold an average 85 percent working interest and an average 72 percent net revenue interest in our wells in these fields.

The Northwest Elk Basin field and South Elk Basin field had estimated total proved reserves at December 31, 2007 of 893 MBOE, 93 percent of which were oil and all of which were proved developed.

Natural Gas Processing Plant

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

The Elk Basin natural gas processing plant is a refrigeration natural gas processing plant that receives natural gas supplies through a natural gas gathering system from fields in the Elk Basin and South Elk Basin fields. The Elk Basin natural gas processing plant currently produces approximately 415 net Bbls of NGLs per day, primarily propane, normal butane, and natural gasoline.

A by-product of our natural gas processing is flue gas.

Pipelines

We own and operate one crude oil pipeline system and two natural gas gathering pipeline systems.

The Clearfork pipeline is regulated by the FERC and transports approximately 4,500 Bbls/D of crude oil from the Elk Basin field and South Elk Basin field to a pipeline operated by Marathon Oil Corporation for further delivery to other markets. Most of the crude oil transported by the Clearfork pipeline is eventually sold to refineries in Billings, Montana. The Clearfork pipeline receives crude oil from various interconnections with local gathering systems.

The Wildhorse pipeline system is an approximately 12-mile natural gas gathering system that transports approximately 6.6 MMcfe/D of low-sulfur natural gas from the Elk Basin and South Elk Basin fields to our Elk Basin natural gas processing plant. The natural gas transported by the Wildhorse gathering system is sold into the WBI Pipeline.

We also own a small natural gas gathering system that transports approximately 12.2 MMcfe/D of high sulfur natural gas from the Elk Basin field to our Elk Basin natural gas processing plant.

15

ENCORE ENERGY PARTNERS LP

Permian Basin Properties

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

For 2007, production from our Permian Basin properties was approximately 738 BOE/D, substantially all of which was natural gas. Our Permian Basin properties had estimated proved reserves at December 31, 2007 of 6,211 MBOE, of which 4,841 MBOE was proved developed and 1,370 MBOE was proved undeveloped. As of December 31, 2007, our Permian Basin properties consisted of 24,649 gross (10,610 net) acres located in Crockett County, Texas. During 2007, we drilled 14 gross (1.4 net) successful wells and 1 gross (0.5 net) unsuccessful well and invested approximately $5.0 million of capital to develop these properties. The preceding information does not include information related to our Permian Basin properties acquired in February 2008. For information regarding our recently acquired properties in the Permian Basin, please read “— Recently Acquired Properties — Permian Basin Properties” below.

The following map depicts the location of our oil and natural gas properties in the Permian Basin.

Operated Properties

We operate 52 gross wells in the Angus and Henderson fields in the Ozona area in Crockett County, Texas. The wells are typically drilled to a depth of approximately 8,000 feet. These wells produce from the Canyon Sand formation. The Canyon Sand produces from several sands over a gross interval of 400 to 500 feet. The wells have been drilled to the allowable 40-acre spacing. We hold an average working interest of 54 percent and an average net revenue interest of 47 percent in these wells.

Non-Operated Properties

We own non-operated interests in the Davidson Ranch, Hunt-Baggett, Live Oak Draw, and Ozona fields in Crockett County, Texas. We hold an average working interest of 32 percent and an average net revenue interest of 23 percent in the wells currently developed in this area. These wells produce from the Canyon Sand and Strawn formations at depths of 8,000 to 9,000 feet. Many of the wells were not completed in all of the known producing intervals.

The Canyon Sand formation in Crockett County is drilled to 40-acre spacing, and many of our non-operated leases have quality drilling locations remaining to be developed. We have identified 1,370 MBOE of proved undeveloped reserves on these properties.

Our properties in Crockett County are operated by several companies, but a majority of the wells are operated by a private oil and gas company that has drilled over 80 wells in Crockett County, Texas since

16

ENCORE ENERGY PARTNERS LP

2000. Historically, we have participated with this company in drilling 2 to 4 wells per year and hold an average working interest of approximately 46 percent.

In 2007, we participated with Chevron Corporation to drill 10 lease line wells. Drilling on this project began in April 2007 and was completed in July 2007. Our working interest in these wells ranges from 2 percent to 7 percent.

Recently Acquired Properties

In February 2008, we acquired certain oil and natural gas producing properties and related assets in the Permian and Williston Basins from Encore Operating for total consideration of approximately $250.4 million.

Permian Basin Properties

The Permian Basin properties are composed of six fields: Crockett, Nolley-McFarland, Dune, North Cowden, Champmon, and Yates.

The Crockett field is located in Crockett County, Texas and consists of gas wells completed in tight sand deposits at 6,500 to 8,500 feet of depth from the Canyon Sand and Strawn formations. The Nolley-McFarland field is located in Andrews County, Texas and produces from the Queen and Wolfcamp formations. The Dune field is a waterflood property located in Crane County, Texas. The North Cowden field is a legacy West Texas field located in Ector County, Texas. The North Cowden field has been undergoing secondary waterflood operations since the 1970’s. More recently, the field has successfully piloted CO₂ injection as a tertiary method for recovering additional oil. The Champmon field is located on a Strawn reef structure in Gaines County, Texas. The field was discovered in 1996 and is drilled on 40-acre spacing.

Williston Basin Properties

The Williston Basin properties are composed of three fields: Horse Creek, Charlson Madison Unit, and Elk.

The Horse Creek field is located in Bowman County, North Dakota and has producing oil wells from multiple horizons in the Red River formation. The Charlson Madison Unit produces from the unitized Madison formation. The Elk field is operated and produces from wells in McKenzie County, North Dakota.

Title to Properties

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

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

•  royalties, overriding royalties, and other burdens under oil and natural gas leases;

•  contractual obligations, including, in some cases, development obligations arising under operating agreements, farmout agreements, production sales contracts, and other agreements that may affect the properties or their titles;

•  liens that arise in the normal course of operations, such as those for unpaid taxes, statutory liens securing unpaid suppliers and contractors, and contractual liens under operating agreements;

•  pooling, unitization, and communitization agreements, declarations, and orders; and

•  easements, restrictions, rights-of-way, and other matters that commonly affect property.

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

17

ENCORE ENERGY PARTNERS LP

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

Environmental Matters and Regulation

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

•  require the acquisition of various permits before development commences;

•  require the installation of expensive pollution control equipment;

•  enjoin some or all of the operations of facilities deemed in non-compliance with permits;

•  restrict the types, quantities, and concentration of various substances that can be released into the environment in connection with oil and natural gas development, production, and transportation activities;

•  restrict the way in which wastes are handled and disposed;

•  limit or prohibit development activities on certain lands lying within wilderness, wetlands, areas inhabited by threatened or endangered species, and other protected areas;

•  require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells;

•  impose substantial liabilities for pollution resulting from operations; and

•  require preparation of a Resource Management Plan, Environmental Assessment and/or an Environmental Impact Statement for operations affecting federal lands or leases.

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

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

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

18

ENCORE ENERGY PARTNERS LP

operations, we generate some amounts of ordinary industrial wastes, such as paint wastes, waste solvents, and waste oils, that may be regulated as hazardous wastes.

Site Remediation.  The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the Superfund law, imposes joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include the current and past owner or operator of the site where the release occurred, and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies. CERCLA authorizes the EPA, and in some cases third parties, to take actions in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.

We currently own, lease, or operate numerous properties that have been used for oil and natural gas exploration and production for many years. Although petroleum, including crude oil, and natural gas are excluded from CERCLA’s definition of “hazardous substance,” in the course of our ordinary operations, we generate wastes that may fall within the definition of a “hazardous substance.” We believe that we have utilized operating and waste disposal practices that were standard in the industry at the time, yet hazardous substances, wastes, or hydrocarbons may have been released on or under the properties owned or leased by us, or on or under other locations, including off-site locations, where such substances have been taken for disposal. In addition, some of our properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons was not under our control. In fact, there is evidence that petroleum spills or releases have occurred in the past at some of the properties owned or leased by us. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA, and analogous state laws. Under such laws, we could be required to remove previously disposed substances and wastes, remediate contaminated property, or perform remedial plugging or pit closure operations to prevent future contamination.

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

The Elk Basin Assets include a natural gas processing plant. Previous environmental investigations of the Elk Basin natural gas processing plant indicate historical soil and groundwater contamination by hydrocarbons and the presence of asbestos-containing material at the site. Although the environmental investigations did not identify an immediate need for remediation of the suspected historical contamination, the extent of the contamination is not known and, therefore, the potential liability for remediating this contamination may be significant. In the event we were to cease operating the gas plant, the cost of decommissioning it and addressing the previously identified environmental conditions and other conditions, such as waste disposal, could be significant. Currently, we do not anticipate ceasing operations at the Elk Basin natural gas processing plant in the near future and do not anticipate a need to commence remedial activities at this time. However, a regulatory agency could require us to begin to investigate and remediate any contamination while the gas plant remains in operation. As of December 31, 2007, we have recorded $4.4 million as future abandonment liability

19

ENCORE ENERGY PARTNERS LP

that represents the estimated cost for decommissioning the Elk Basin natural gas processing plant. Due to the significant level of uncertainty associated with the known and unknown environmental liabilities at the gas plant, our estimates of the future abandonment liability include a large contingency. In addition to the future abandonment liability recorded for the Elk Basin plant, we have recorded an estimated liability of $1.0 million as of December 31, 2007 related to required environmental plant compliance costs caused by past operations of the plant. The liability was assumed from Anadarko when the Elk Basin Assets were purchased. Our estimates of future abandonment liability and compliance costs are subject to change. The actual cost of these items could vary significantly.

Water Discharges.  The Clean Water Act (“CWA”), and analogous state laws, impose strict controls on the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. The CWA regulates storm water run-off from oil and natural gas facilities and requires a storm water discharge permit for certain activities. Such a permit requires the regulated facility to monitor and sample storm water run-off from its operations. The CWA and regulations implemented thereunder also prohibit discharges of dredged and fill material in wetlands and other waters of the United States unless authorized by an appropriately issued permit. Spill prevention, control, and countermeasure requirements of the CWA require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture, or leak. Federal and state regulatory agencies can impose administrative, civil, and criminal penalties for non-compliance with discharge permits or other requirements of the CWA and analogous state laws and regulations.

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

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

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

Recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases” and including carbon dioxide and methane, may be contributing to warming of the Earth’s atmosphere. In response to such studies, the U.S. Congress is actively considering legislation to reduce

20

ENCORE ENERGY PARTNERS LP

emissions of greenhouse gases. In addition, at least 14 states have declined to wait on Congress to develop and implement climate control legislation and have already taken legal measures to reduce emissions of greenhouse gases. Also, as a result of the U.S. Supreme Court’s decision on April 2, 2007 in Massachusetts, et al. v. EPA, the EPA must consider whether it is required to regulate greenhouse gas emissions from mobile sources (e.g., cars and trucks) even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. The Court’s holding in Massachusetts that greenhouse gases fall under the federal CAA’s definition of “air pollutant” may also result in future regulation of greenhouse gas emissions from stationary sources under various CAA programs, including those used in oil and natural gas exploration and production operations. It is not possible at this time to predict how legislation that may be enacted to address greenhouse gas emissions would impact the oil and natural gas exploration and production business. However, future laws and regulations could result in increased compliance costs or additional operating restrictions, and could have a material adverse effect on our business, financial condition, demand for our operations, results of operations, and cash flows.

Activities on Federal Lands.  Oil and natural gas exploration and production activities on federal lands are subject to the National Environmental Policy Act (“NEPA”). NEPA requires federal agencies, including the Department of the Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect, and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. All of our current exploration and production activities, as well as proposed exploration and development plans, on federal lands require governmental permits that are subject to the requirements of NEPA. This process has the potential to delay the development of oil and natural gas projects.

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

We believe that we are in substantial compliance with all existing environmental laws and regulations applicable to our current operations and that our continued compliance with existing requirements will not have a material adverse impact on our financial condition and results of operations. We did not incur any material capital expenditures for remediation or pollution control activities during 2007, and, as of the date of this Report, we are not aware of any environmental issues or claims that will require material capital expenditures during 2008. However, accidental spills or releases may occur in the course of our operations, and we may incur substantial costs and liabilities as a result of such spills or releases, including those relating to claims for damage to property and persons. Moreover, the passage of more stringent laws or regulations in the future may have a negative impact on our business, financial condition, results of operations, or ability to make distributions.

Other Regulation of the Oil and Natural Gas Industry

The oil and natural gas industry is extensively regulated by numerous federal, state, and local authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities, and locations of production.

21

ENCORE ENERGY PARTNERS LP

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

Development and Production.  Our operations are subject to various types of regulation at the federal, state, and local levels. These types of regulation include requiring permits for the development of wells, development bonds, and reports concerning operations. Most states, and some counties and municipalities, in which we operate also regulate one or more of the following:

•  the location of wells;

•  the method of developing and casing wells;

•  the surface use and restoration of properties upon which wells are drilled;

•  the plugging and abandoning of wells; and

•  the notification of surface owners and other third parties.

State laws regulate the size and shape of development and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploitation while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas, and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas, and NGLs within its jurisdiction.

Interstate Crude Oil Transportation.  Our Clearfork crude oil pipeline is an interstate common carrier pipeline, which is subject to regulation by the Federal Energy Regulatory Commission (“FERC”) under the October 1, 1977 version of the Interstate Commerce Act (“ICA”) and the Energy Policy Act of 1992 (“EP Act 1992”). The ICA and its implementing regulations give the FERC authority to regulate the rates we charge for service on that interstate common carrier pipeline and generally require the rates and practices of interstate oil pipelines to be just and reasonable and nondiscriminatory. The ICA also requires us to maintain tariffs on file with the FERC that set forth the rates we charge for providing transportation services on our interstate common carrier liquids pipeline as well as the rules and regulations governing these services. Shippers may protest, and the FERC may investigate, the lawfulness of new or changed tariff rates. The FERC can suspend those tariff rates for up to seven months. It can also require refunds of amounts collected pursuant to rates that are ultimately found to be unlawful. The FERC and interested parties can also challenge tariff rates that have become final and effective. EP Act 1992 deemed certain rates in effect prior to its passage to be just and reasonable and limited the circumstances under which a complaint can be made against such “grandfathered” rates. EP Act 1992 and its implementing regulations also allow interstate common carrier oil pipelines to annually index their rates up to a prescribed ceiling level. In addition, the FERC retains cost-of-service ratemaking, market-based rates, and settlement rates as alternatives to the indexing approach.

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

22

ENCORE ENERGY PARTNERS LP

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

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

The Energy Policy Act of 2005 (“EP Act 2005”) gave the FERC increased oversight and penalty authority regarding market manipulation and enforcement. EP Act 2005 amended the NGA to prohibit market manipulation and also amended the NGA and the Natural Gas Policy Act of 1978 (“NGPA”) to increase civil and criminal penalties for any violations of the NGA, NGPA, and any rules, regulations, or orders of the FERC to up to $1,000,000 per day, per violation. In addition, the FERC issued a final rule effective January 26, 2006 regarding market manipulation, which makes it unlawful for any entity, in connection with the purchase or sale of natural gas or transportation service subject to the FERC’s jurisdiction, to defraud, make an untrue statement, or omit a material fact, or engage in any practice, act, or course of business that operates or would operate as a fraud. This final rule works together with the FERC’s enhanced penalty authority to provide increased oversight of the natural gas marketplace.

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

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

States also regulate the method of developing new fields, the spacing and operation of wells, and the prevention of waste of oil and natural gas resources. States may regulate rates of production and may establish maximum daily production allowables from oil and natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but there can be no assurance that they will not do so in the future. The effect of these regulations

23

ENCORE ENERGY PARTNERS LP

may be to limit the amounts of oil and natural gas that may be produced from our wells, and to limit the number of wells or locations we can drill.

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

Operating Hazards and Insurance

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

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

Employees

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

EAC had a staff of 364 persons, including 39 engineers, 16 geologists, and 15 landmen as of December 31, 2007. None of these employees are represented by labor unions or covered by any collective bargaining agreement. We believe that EAC’s relations with its employees are satisfactory.

Principal Executive Offices

Our principal executive offices are located at 777 Main Street, Suite 1400, Fort Worth, Texas 76102, which is also where EAC’s principal executive offices are located. Our main telephone number is (817) 877-9955.

Available Information

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

We have adopted a code of business conduct and ethics that applies to all directors, officers, and employees, including our principal executive officer and principal financial officer. The code of business conduct and ethics is available on our website (www.encoreenp.com). In the event that we make changes in, or

24

ENCORE ENERGY PARTNERS LP

provide waivers from, the provisions of this code of business conduct and ethics that the SEC or the NYSE requires us to disclose, we intend to disclose these events on our website.

The board of directors of our general partner currently has two standing committees: (i) audit and (ii) conflicts. The NYSE does not require a listed limited partnership like us to have a majority of independent directors on the board of directors of our general partner or to establish a compensation committee or a nominating and corporate governance committee.

The code of business conduct and ethics and audit committee charter are available on our website. Copies of the code of business conduct and ethics and the audit committee charter are also available in print upon written request to the Corporate Secretary, Encore Energy Partners GP LLC, 777 Main Street, Suite 1400, Fort Worth, Texas 76102.

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

25

ENCORE ENERGY PARTNERS LP

ITEM 1A.   RISK FACTORS

The following factors should be carefully considered together with all of the other information contained in this Report. If any of the following risks and uncertainties described below or elsewhere in this Report were actually to occur, our business, financial condition, or results of operations could be materially adversely affected. In that case, we may not be able to pay distributions on our common units, the trading price of our common units could decline, and unitholders could lose all or part of their investment.

Risks Related to Our Business

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

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

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

•  the level of our capital expenditures;

•  our ability to make borrowings under our revolving credit facility to pay distributions;

•  sources of cash used to fund acquisitions;

•  debt service requirements and restrictions on distributions contained in our revolving credit facility or future debt agreements;

•  interest payments;

•  fluctuations in our working capital needs;

•  general and administrative expenses;

•  cash settlement of commodity derivative contracts;

•  timing and collectibility of receivables; and

•  the amount of cash reserves established by our general partner for the proper conduct of our business.

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

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

Because our oil and natural gas properties are a depleting asset, we need to make substantial capital expenditures to maintain and grow our asset base, which reduce our cash available for distribution. Because the timing and amount of these capital expenditures fluctuate each quarter, we expect to reserve substantial amounts of cash each quarter to finance these expenditures over time. We may use the reserved cash to reduce

26

ENCORE ENERGY PARTNERS LP

indebtedness until we make the capital expenditures. Over a longer period of time, if we do not set aside sufficient cash reserves or make sufficient expenditures to maintain our asset base, we will be unable to pay distributions at the current level from cash generated from operations and would therefore expect to reduce our distributions.

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

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

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

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

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

Oil and natural gas prices are very volatile. A decline in commodity prices will cause a decline in our cash flow from operations, which may force us to reduce our distributions or cease paying distributions altogether.

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

•  domestic and foreign supply of and demand for oil and natural gas;

•  weather conditions;

•  overall domestic and global economic conditions;

•  political and economic conditions in oil and natural gas producing countries, including those in the Middle East and South America;

•  actions of the Organization of Petroleum Exporting Countries and other state-controlled oil companies relating to oil price and production controls;

•  impact of the U.S. dollar exchange rates on oil and natural gas prices;

27

ENCORE ENERGY PARTNERS LP

•  technological advances affecting energy consumption and energy supply;

•  domestic and foreign governmental regulations and taxation;

•  the impact of energy conservation efforts;

•  the proximity, capacity, cost, and availability of oil and natural gas pipelines and other transportation facilities;

•  the availability of refining capacity; and

•  the price and availability of alternative fuels.

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

•  negatively impact the value of our reserves, because declines in oil and natural gas prices would reduce the amount of oil and natural gas that we can produce economically;

•  reduce the amount of cash flow available for capital expenditures;

•  limit our ability to borrow money or raise additional capital; and

•  impair our ability to pay distributions.

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

An increase in the differential between the NYMEX or other benchmark prices of oil and natural gas and the wellhead price we receive could significantly reduce our cash available for distribution and adversely affect our financial condition.

The prices that we receive for our oil and natural gas production sometimes trade at a discount to the relevant benchmark prices, such as NYMEX, that are used for calculating commodity derivative settlements. The difference between the benchmark price and the price we receive is called a differential. We cannot accurately predict oil and natural gas differentials. The oil production from our Elk Basin Assets sells at a higher discount to NYMEX as compared to our Permian Basin Assets due to production increases from competing Canadian and Rocky Mountain producers, in conjunction with limited refining and pipeline capacity from the Rocky Mountain area, and corresponding deep pricing discounts by regional refiners. Increases in the differential between the benchmark price for oil and natural gas and the wellhead price we receive could significantly reduce our cash available for distribution and adversely affect our financial condition. For information regarding our expected differentials for 2008, please read “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Future price declines may result in a write-down of our asset carrying values, which could have a material adverse effect on our results of operations and limit our ability to borrow and make distributions.

Declines in oil and natural gas prices may result in our having to make substantial downward adjustments to our estimated proved reserves. If this occurs, or if our estimates of development costs increase, production data factors change or development results deteriorate, accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties. If we incur such impairment charges in the future, it could have a material adverse effect on our results of operations in the period incurred and on our ability to borrow funds under our revolving credit facility, which in turn may adversely affect our ability to make cash distributions to our unitholders.

28

ENCORE ENERGY PARTNERS LP

Our commodity derivative contract activities could result in financial losses or could reduce our income, which may adversely affect our ability to pay distributions to our unitholders.

To achieve more predictable cash flow and to reduce our exposure to adverse fluctuations in the prices of oil and natural gas, we currently and may in the future enter into derivative arrangements for a significant portion of our oil and natural gas production that could result in commodity derivative losses. The extent of our commodity price exposure is related largely to the effectiveness and scope of our derivative activities. For example, the derivative instruments we utilize are based on posted market prices, which may differ significantly from the actual crude oil, natural gas, and NGL prices we realize in our operations.

Our actual future production may be significantly higher or lower than we estimate at the time we enter into derivative transactions for such period. If the actual amount is higher than we estimate, we will have greater commodity price exposure than we intended. If the actual amount is lower than the notional amount of our derivative financial instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of the cash flow from the sale of the underlying physical commodity, resulting in a substantial diminution of our liquidity. As a result of these factors, our derivative activities may not be as effective as we intend in reducing the volatility of our cash flows, and in certain circumstances may actually increase the volatility of our cash flows. In addition, our derivative activities are subject to the following risks:

•  a counterparty may not perform its obligation under the applicable derivative instrument; and

•  there may be a change in the expected differential between the underlying commodity price in the derivative instrument and the actual price received, which may result in payments to our derivative counterparty that are not accompanied by our receipt of higher prices from our production in the field.

Our estimated proved reserves are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

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

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

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

The Standardized Measure of our estimated proved reserves is not necessarily the same as the current market value of our estimated proved oil and natural gas reserves. We base the estimated discounted future net cash flows from our estimated proved reserves on prices and costs in effect on the day of estimate.

29

ENCORE ENERGY PARTNERS LP

The timing of both our production and our incurrence of expenses in connection with the development and production of oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10 percent discount factor we use when calculating discounted future net cash flows in compliance with the Financial Accounting Standards Board’s (“FASB”) Statement of Financial Accounting Standards (“SFAS”) No. 69, Disclosures about Oil and Gas Producing Activities, may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general.

Developing and producing oil and natural gas are costly and high-risk activities with many uncertainties that could adversely affect our financial condition or results of operations and, as a result, our ability to pay distributions to our unitholders.

The cost of developing, completing, and operating a well is often uncertain, and cost factors can adversely affect the economics of a well. Our efforts will be uneconomical if we drill dry holes or wells that are productive but do not produce as much oil and natural gas as we had estimated. Furthermore, our development and producing operations may be curtailed, delayed, or canceled as a result of other factors, including:

•  high costs, shortages, or delivery delays of rigs, equipment, labor, or other services;

•  unexpected operational events and/or conditions;

•  reductions in oil and natural gas prices;

•  increases in severance taxes;

•  limitations in the market for oil and natural gas;

•  adverse weather conditions and natural disasters;

•  facility or equipment malfunctions, and equipment failures or accidents;

•  title problems;

•  pipe or cement failures and casing collapses;

•  compliance with environmental and other governmental requirements;

•  environmental hazards, such as natural gas leaks, oil spills, pipeline ruptures, and discharges of toxic gases;

•  lost or damaged oilfield development and service tools;

•  unusual or unexpected geological formations, and pressure or irregularities in formations;

•  loss of drilling fluid circulation;

•  fires, blowouts, surface craterings, and explosions;

•  uncontrollable flows of oil, natural gas, or well fluids; and

•  loss of leases due to incorrect payment of royalties.

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

30

ENCORE ENERGY PARTNERS LP

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

Approximately 70 percent of our production and 65 percent of our reserves as of December 31, 2007 rely on secondary and tertiary recovery techniques, which include waterfloods and injecting natural gases into producing formations to enhance hydrocarbon recovery. If production response is less than forecast for a particular project, then the project may be uneconomic or generate less cash flow and reserves than we had estimated prior to investing capital. Risks associated with secondary and tertiary recovery techniques include, but are not limited to, the following:

•  lower-than-expected production;

•  longer response times;

•  higher capital costs;

•  shortages of equipment; and

•  lack of technical expertise.

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

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

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

If we do not make acquisitions on economically acceptable terms, our future growth and ability to pay or increase distributions will be limited.

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

•  unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them;

•  unable to obtain financing for these acquisitions on economically acceptable terms; or

•  outbid by competitors.

If we are unable to acquire properties containing proved reserves, our total level of proved reserves will decline as a result of our production, and we will be limited in our ability to increase or possibly even to maintain our level of cash distributions.

31

ENCORE ENERGY PARTNERS LP

Any acquisitions we complete are subject to substantial risks that could reduce our ability to make distributions to unitholders.

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

•  the validity of our assumptions about reserves, future production, revenues, capital expenditures, operating expenses, and costs, including synergies;

•  an inability to integrate the businesses we acquire successfully;

•  a decrease in our liquidity by using a significant portion of our available cash or borrowing capacity to finance acquisitions;

•  a significant increase in our interest expense or financial leverage if we incur additional debt to finance acquisitions;

•  the assumption of unknown liabilities, losses, or costs for which we are not indemnified or for which our indemnity is inadequate;

•  the diversion of management’s attention from other business concerns;

•  an inability to hire, train, or retain qualified personnel to manage and operate our growing business and assets;

•  natural disasters;

•  the incurrences of other significant charges, such as impairment of goodwill or other intangible assets, asset devaluation, or restructuring charges;

•  unforeseen difficulties encountered in operating in new geographic areas; and

•  customer or key employee losses at the acquired businesses.

Our decision to acquire a property depends in part on the evaluation of data obtained from production reports and engineering studies, geophysical and geological analyses, and seismic and other information, the results of which are often inconclusive and subject to various interpretations.

Also, our reviews of acquired properties are inherently incomplete because it generally is not feasible to perform an in-depth review of the individual properties involved in each acquisition given time constraints imposed by sellers. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential. Inspections may not always be performed on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken.

Due to our lack of asset and geographic diversification, adverse developments in our operating areas would reduce our ability to make distributions to our unitholders.

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

32

ENCORE ENERGY PARTNERS LP

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

For 2007, Marathon Oil Corporation and ConocoPhillips accounted for approximately 52 percent and 16 percent of our total sales of production, respectively. If either of these customers were to reduce the production it purchases from us, our revenue and cash available for distribution will decline to the extent we are not able to find new customers for our production.

We may be unable to compete effectively with larger companies, which may adversely affect our ability to generate sufficient revenue to allow us to pay distributions to our unitholders.

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

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

We may be unable to pay a distribution at the current distribution rate or a future distribution rate without borrowing under our revolving credit facility. When we borrow to pay distributions, we are distributing more cash than we are generating from our operations on a current basis. This means that we are using a portion of our borrowing capacity under our revolving credit facility to pay distributions rather than to maintain or expand our operations. If we use borrowings under our revolving credit facility to pay distributions for an extended period of time rather than toward funding capital expenditures and other matters relating to our operations, we may be unable to support or grow our business. Such a curtailment of our business activities, combined with our payment of principal and interest on our future indebtedness to pay these distributions, will reduce our cash available for distribution on our units and will have a material adverse effect on our business, financial condition, and results of operations. If we borrow to pay distributions during periods of low commodity prices and commodity prices remain low, we may have to reduce our distribution in order to avoid excessive leverage.

33

ENCORE ENERGY PARTNERS LP

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

As of February 25, 2008, we had $169.5 million of outstanding borrowings under our revolving credit facility. We have the ability to incur additional debt under our revolving credit facility, subject to borrowing base limitations. Our future indebtedness could have important consequences to us, including:

•  our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions, or other purposes may be impaired or such financing may not be available on favorable terms;

•  covenants contained in our future debt arrangements may require us to meet financial tests that may affect our flexibility in planning for and reacting to changes in our business, including possible acquisition opportunities;

•  we will need a substantial portion of our cash flow to make principal and interest payments on our indebtedness, reducing the funds that would otherwise be available for operations, future business opportunities, and distributions to unitholders; and

•  our debt level will make us more vulnerable to competitive pressures, a downturn in our business, or the economy generally, than our competitors with less debt.

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

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

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

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

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

34

ENCORE ENERGY PARTNERS LP

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

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

We are not fully insured against all risks, including development and completion risks that are generally not recoverable from third parties or insurance. In addition, pollution and environmental risks generally are not fully insurable. Additionally, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses could, therefore, occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. Moreover, insurance may not be available in the future at commercially reasonable costs and on commercially reasonable terms. Changes in the insurance markets due to terrorist attacks and hurricanes have made it more difficult for us to obtain certain types of coverage. We may not be able to obtain the levels or types of insurance we would otherwise have obtained prior to these market changes, and our insurance may contain large deductibles or fail to cover certain hazards or cover all potential losses. Losses and liabilities from uninsured and underinsured events and delay in the payment of insurance proceeds could have a material adverse effect on our business, financial condition, results of operations, and ability to make distributions to our unitholders.

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

The marketability of our oil and natural gas production depends in part on the availability, proximity, and capacity of pipelines, oil and natural gas gathering systems, and processing facilities. The amount of oil and natural gas that can be produced and sold is subject to curtailment in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, physical damage, or lack of available capacity on such systems. The curtailments arising from these and similar circumstances may last from a few days to several months. In many cases, we are provided only with limited, if any, notice as to when these circumstances will arise and their duration. Any significant curtailment in gathering system or pipeline capacity could reduce our ability to market our oil and natural gas production and harm our business.

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

Other companies operated approximately 25 percent of our properties (measured by total reserves) and approximately 36 percent of our wells as of December 31, 2007. We have limited ability to influence or control the operation or future development of these non-operated properties or the amount of capital expenditures that we are required to fund with respect to them. Our dependence on the operator and other working interest owners for these projects and our limited ability to influence or control the operation and future development of these properties could materially adversely affect the realization of our targeted returns on capital in drilling or acquisition activities and lead to unexpected future costs.

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

Our oil and natural gas exploration and production operations are subject to complex and stringent laws and regulations. Environmental and other governmental laws and regulations have increased the costs to plan,

35

ENCORE ENERGY PARTNERS LP

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

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

Our operations expose us to significant costs and liabilities with respect to environmental and operational safety matters.

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

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

The amount of cash distributions that we will be able to distribute to unitholders will be reduced by the costs associated with being a public company, other general and administrative expenses, and reserves that our general partner believes prudent to maintain for the proper conduct of our business and for future distributions.

Before we can pay distributions to our unitholders, we must first pay or reserve cash for our expenses, including capital expenditures, the costs of being a public company, and other operating expenses, and we may reserve cash for future distributions during periods of limited cash flows. The amount of cash we have available for distribution to our unitholders will be affected by our level of reserves and expenses, including the costs associated with being a public company.

Risks Inherent in an Investment in Us

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

As of February 20, 2008, affiliates of EAC owned approximately 67 percent of our outstanding common units and controlled our general partner, which controls us. The directors and officers of our general partner

36

ENCORE ENERGY PARTNERS LP

have a fiduciary duty to manage our general partner in a manner beneficial to EAC. Furthermore, certain directors and officers of our general partner are directors and officers of affiliates of our general partner, including EAC. Conflicts of interest may arise between EAC and its affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand. As a result of these conflicts, our general partner may favor its own interests and the interests of its affiliates over the interests of our unitholders. These potential conflicts include, among others, the following situations:

•  neither our partnership agreement nor any other agreement requires EAC or its affiliates (other than our general partner) to pursue a business strategy that favors us. EAC’s directors and officers have a fiduciary duty to make these decisions in the best interests of its shareholders, which may be contrary to our interests;

•  our general partner is allowed to take into account the interests of parties other than us, such as EAC and its affiliates, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to our unitholders;

•  EAC is not limited in its ability to compete with us and is under no obligation to offer to sell assets to us;

•  under the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, does not apply to our general partner or its affiliates (including EAC) and no such person who acquires knowledge of a potential transaction, agreement, arrangement, or other matter that may be an opportunity for our partnership will have any duty to communicate or offer such opportunity to us;

•  some officers of our general partner who provide services to us will devote time to affiliates of our general partner and may be compensated for services rendered to such affiliates;

•  our general partner has limited its liability and reduced its fiduciary duties, and has also restricted the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty. Unitholders are deemed to have consented to some actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable law;

•  our general partner determines the amount and timing of asset purchases and sales, borrowings, issuance of additional partnership securities, and cash reserves, each of which can affect the amount of cash that is distributed to unitholders;

•  we entered into an administrative services agreement with Encore Operating pursuant to which Encore Operating performs administrative services for us. Under the administrative services agreement, Encore Operating receives 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 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;

•  our general partner may cause us to borrow funds in order to permit the payment of cash distributions;

•  our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf;

•  our general partner has limited its liability regarding our contractual and other obligations and, in some circumstances, is entitled to be indemnified by us;

•  our general partner may exercise its limited right to call and purchase common units if it and its affiliates own more than 80 percent of the common units;

37

ENCORE ENERGY PARTNERS LP

•  our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates; and

•  our general partner decides whether to retain separate counsel, accountants, or others to perform services for us.

EAC is not limited in its ability to compete with us, which could limit our ability to acquire additional assets or businesses.

Our partnership agreement does not prohibit EAC from owning assets or engaging in businesses that compete directly or indirectly with us. In addition, EAC may acquire, develop, or dispose of additional oil and natural gas properties or other assets in the future, without any obligation to offer us the opportunity to purchase or develop any of those assets. EAC is a large, established participant in the oil and natural gas industry, and has significantly greater resources and experience than we have, which factors may make it more difficult for us to compete with EAC with respect to commercial activities as well as for acquisition candidates. As a result, competition from EAC could adversely impact our results of operations and cash available for distribution.

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

Since an affiliate of EAC owns our general partner, it has the ability to elect all the members of the board of directors of our general partner. Our general partner has control over all decisions related to our operations. Since affiliates of EAC also owned approximately 67 percent of our outstanding common units as of February 20, 2008, the public unitholders do not have the ability to influence any operating decisions and are not able to prevent us from entering into most transactions. Furthermore, the goals and objectives of EAC and our general partner relating to us may not be consistent with those of a majority of the public unitholders.

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

None of the officers of our general partner are employees of our general partner, and we do not have any employees. We entered into an administrative services agreement with Encore Operating pursuant to which Encore Operating performs administrative services for us. Affiliates of our general partner and Encore Operating conduct businesses and activities of their own in which we have no economic interest, including businesses and activities relating to EAC. If these separate activities are significantly greater than our activities, there could be material competition for the time and effort of the officers and employees who provide services to our general partner, EAC, and their affiliates. If the officers of our general partner and the employees of EAC and their affiliates do not devote sufficient attention to the management and operation of our business, our financial results may suffer and our ability to make distributions to our unitholders may be reduced.

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

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

•  permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or

38

ENCORE ENERGY PARTNERS LP

factors affecting, us, our affiliates, or any limited partner. Examples include the exercise of its limited call right, the exercise of its rights to transfer or vote the units it owns, the exercise of its registration rights, and its determination whether or not to consent to any merger or consolidation of the partnership or amendment to the partnership agreement;

•  provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as it acted in good faith;

•  generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the conflicts committee of the board of directors of our general partner acting in good faith and not involving a vote of unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or must be “fair and reasonable” to us, as determined by our general partner in good faith. In determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us;

•  provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for any acts or omissions unless there has been a final and nonappealable judgment entered by a court of competent jurisdiction determining that the general partner or its officers and directors acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and

•  provides that in resolving conflicts of interest, it will be presumed that in making its decision the general partner or its conflict committee acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.

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

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

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

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

The unitholders are unable to remove our general partner without its consent because our general partner and its affiliates own sufficient units to be able to prevent its removal. The vote of the holders of at least 662/3 percent of all outstanding units voting together as a single class is required to remove the general partner. As of February 20, 2008, our general partner and its affiliates owned approximately 67 percent of our outstanding common units.

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

Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, our partnership agreement does not restrict the ability of EAC, the owner of our general partner, from transferring all or a portion of its ownership interest in our general partner to a third party. The new owner of our general partner would then be

39

ENCORE ENERGY PARTNERS LP

in a position to replace the board of directors and officers of our general partner with its own choices and thereby influence the decisions made by the board of directors and officers.

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

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

•  our unitholders’ proportionate ownership interest in us will decrease;

•  the amount of cash available for distribution on each unit may decrease;

•  the ratio of taxable income to distributions may increase;

•  the relative voting strength of each previously outstanding unit may be diminished; and

•  the market price of the common units may decline.

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

Our partnership agreement restricts unitholders’ voting rights by providing that any common units held by a person, entity, or group that owns 20 percent or more of any class of common units then outstanding, other than our general partner, its affiliates, their transferees, and persons who acquired such common units with the prior approval of the board of directors of our general partner, cannot vote on any matter. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting unitholders’ ability to influence the manner or direction of management.

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

As of February 20, 2008, EAC held an aggregate of 20,924,055 common units. The sale of these units in the public markets could have an adverse impact on the price of the common units.

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

If at any time our general partner and its affiliates own more than 80 percent of the common units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than their then-current market price. As a result, unitholders may be required to sell their common units at an undesirable time or price and may not receive any return on their investment. Unitholders also may incur a tax liability upon a sale of their common units. As of February 20, 2008, our general partner and its affiliates owned approximately 67 percent of our outstanding common units.

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

A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law and we conduct business in a number of

40

ENCORE ENERGY PARTNERS LP

other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. A unitholder could be liable for our obligations as if it was a general partner if:

•  a court or government agency determined that we were conducting business in a state but had not complied with that particular state’s partnership statute; or

•  a unitholder’s rights to act with other unitholders to remove or replace the general partner, to approve some amendments to our partnership agreement, or to take other actions under our partnership agreement constitute “control” of our business.

Unitholders may have liability to repay distributions.

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

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

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

•  a citizen of the United States;

•  a corporation organized under the laws of the United States or of any state thereof;

•  a public body, including a municipality; or

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

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

An increase in interest rates may cause the market price of our common units to decline.

Like all equity investments, an investment in our common units is subject to certain risks. In exchange for accepting these risks, investors may expect to receive a higher rate of return than would otherwise be

41

ENCORE ENERGY PARTNERS LP

obtainable from lower-risk investments. Accordingly, as interest rates rise, the ability of investors to obtain higher risk-adjusted rates of return by purchasing government-backed debt securities may cause a corresponding decline in demand for riskier investments generally, including yield-based equity investments such as publicly traded limited partnership interests. Reduced demand for our common units resulting from investors seeking other more favorable investment opportunities may cause the trading price of our common units to decline.

Tax Risks to Common Unitholders

Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of additional entity-level taxation by individual states. If the IRS were to treat us as a corporation or if we were to become subject to a material amount of additional entity-level taxation for state tax purposes, then our cash available for distribution to unitholders would be substantially reduced.

The anticipated after-tax economic benefit of an investment in the common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested a ruling from the IRS on this or any other tax matter affecting us.

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

Current law may change, so as to cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to entity-level taxation. In addition, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise, and other forms of taxation. For example, we are subject to a new entity-level tax, the Texas margin tax, at an effective rate of up to 0.7 percent on the portion of our income that is apportioned to Texas beginning with tax reports due on or after January 1, 2008. Imposition of such a tax on us by Texas or any other state will reduce the cash available for distribution to unitholders.

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

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

42

ENCORE ENERGY PARTNERS LP

We prorate our items of income, gain, loss, and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss, and deduction among our unitholders.

We prorate our items of income, gain, loss, and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury regulations, and, accordingly, our counsel is unable to opine as to the validity of this method. If the IRS were to challenge this method or new Treasury regulations were issued, we may be required to change the allocation of items of income, gain, loss, and deduction among our unitholders.

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

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

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

Because our unitholders are treated as partners to whom we allocate taxable income which could be different in amount than the cash we distribute, unitholders are required to pay any federal income taxes and, in some cases, state and local income taxes on their share of our taxable income, even if they receive no cash distributions from us. Unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from their share of our taxable income.

Tax gain or loss on the disposition of our common units could be more or less than expected.

If unitholders sell their common units, they will recognize a gain or loss equal to the difference between the amount realized and their tax basis in those common units. Prior distributions to unitholders in excess of the total net taxable income they were allocated for a common unit, which decreased their tax basis in that common unit, will, in effect, become taxable income to unitholders if the common unit is sold at a price greater than their tax basis in that common unit, even if the price they receive is less than their original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income. In addition, if unitholders sell their common units, they may incur a tax liability in excess of the amount of cash they receive from the sale.

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

Investment in common units by tax-exempt entities, such as individual retirement accounts (known as IRAs) and other retirement plans, and non-United States persons raises issues unique to them. For example, virtually all of our income allocated to organizations exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-United States persons will be reduced by withholding taxes at the highest applicable effective tax rate,

43

ENCORE ENERGY PARTNERS LP

and non-United States persons will be required to file United States federal income tax returns and pay tax on their share of our taxable income.

A unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of those units. If so, he would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.

Because a unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of the loaned units, he may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss, or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Our tax counsel has not rendered an opinion regarding the treatment of a unitholder where common units are loaned to a short seller to cover a short sale of common units; therefore, unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.

We will treat each purchaser of common units as having the same tax benefits without regard to the common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.

Because we cannot match transferors and transferees of common units, we will adopt depletion, depreciation and amortization positions that may not conform with all aspects of existing Treasury regulations. Our counsel is unable to opine as to the validity of such filing positions. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to unitholders. It also could affect the timing of these tax benefits or the amount of gain from unitholders’ sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to unitholder tax returns.

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

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

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

We will be considered to have terminated for tax purposes if there is a sale or exchange of 50 percent or more of the total interests in our capital and profits within a twelve-month period. Our termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and unitholders receiving two schedule K-1s) for one fiscal year and require a unitholder who uses a different taxable year than us to include more than twelve moths of our taxable income or loss in his taxable income for the year of our termination.

44

ENCORE ENERGY PARTNERS LP

We may adopt certain valuation methodologies that may result in a shift of income, gain, loss, and deduction between the holders of the management incentive units and the unitholders. The IRS may challenge this treatment, which could adversely affect the value of our common units.

When we issue additional units or engage in certain other transactions, we will determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and the holders of the management incentive units. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss, and deduction between certain unitholders and the holders of the management incentive units, which may be unfavorable to such unitholders. Moreover, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of income, gain, loss, and deduction between the holders of the management incentive units and certain of our unitholders.

A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.

ITEM 1B.   UNRESOLVED STAFF COMMENTS

There were no unresolved SEC staff comments as of December 31, 2007.

ITEM 2.   PROPERTIES

Information regarding our oil and natural gas properties is contained in “Item 1. Business.”

ITEM 3.   LEGAL PROCEEDINGS

From time to time, we are a party to ongoing 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 us.

ITEM 4.   SUBMISSION OF MATTERS TO A VOTE OF UNITHOLDERS

There were no matters submitted to unitholders during the fourth quarter of 2007.

45

ENCORE ENERGY PARTNERS LP

PART II

ITEM 5.   MARKET FOR REGISTRANT’S COMMON UNITS, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF COMMON UNITS

Our common units began trading on the NYSE under the symbol “ENP” commencing with our IPO on September 12, 2007. The following table sets forth the range of daily high and low sales prices of our common units and cash distributions to our common unitholders for the periods indicated:

	Price Range				Cash Distribution
2007	High		Low		per Common Unit(a)
Quarter ended December 31	$	21.50	$	16.56	$	0.3875
Quarter ended September 30		22.25		20.10		0.0530

(a) On October 29, 2007, the board of directors of our general partner declared a distribution for the third quarter of 2007. The distribution was paid on November 14, 2007 and was based on an initial quarterly distribution of $0.35 per unit, prorated for the period from and including September 17, 2007 (the closing date of the IPO) through September 30, 2007. On January 21, 2008, the board of directors of our general partner declared a distribution with respect to the fourth quarter of 2007, which was payable on or about February 14, 2008 to unitholders of record as of the close of business on February 6, 2008.

On February 20, 2008, the closing sales price of our common units as reported by the NYSE was $20.69 per unit. At the close of business on February 20, 2008, we had approximately 40 unitholders of record. This number does not include owners for whom common units may be held in “street” name.

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

The following table summarizes purchases of our common units during the fourth quarter of 2007:

						Total Number of		Approximate Dollar
						Units Purchased		Value of Units
	Total Number		Average Price			as Part of Publicly		That May Yet Be
	of Common Units		Paid per			Announced Plans		Purchased Under the
Month	Purchased		Common Unit			or Programs		Plans or Programs
October		22,968		(a	)		—
November		—	$	—			—
December		—	$	—			—
Total		22,968	$	—			—	$	—

(a) In connection with the exercise by the underwriters of their option to purchase additional common units in the IPO, pursuant to the contribution agreement with our general partner, EAC, Encore Operating, Encore Partners LP Holdings LLC, and Encore Energy Partners Operating LLC, 22,968 common units owned by Encore Partners LP Holdings LLC were transferred to our general partner, which our general partner exchanged with us for an equal number of general partner units in us in order to maintain its 2 percent general partner interest.

Cash Distributions to Unitholders

Our partnership agreement requires that, within 45 days after the end of each quarter, we distribute all of our available cash to unitholders of record on the applicable record date. The term “available cash,” for any quarter, means all cash and cash equivalents on hand at the end of that quarter, less the amount of cash reserves established by our general partner to:

•  provide for the proper conduct of our business;

46

ENCORE ENERGY PARTNERS LP

•  comply with applicable law, any of our debt instruments, or other agreements; or

•  provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters.

Our partnership agreement gives our general partner wide latitude to establish reserves for future capital expenditures and operational needs prior to determining the amount of cash available for distribution.

We distribute available cash to our unitholders and our general partner in accordance with their ownership percentages. In distributing available cash, we assume 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 our unitholders at the time of any such distribution. If the 5.1 percent maximum limit on aggregate distributions to the holders of our management incentive units is reached, then any available cash that would have been distributed to such holders will be available for distribution to our unitholders.

Unregistered Sales of Equity Securities

In connection with our formation on February 13, 2007, we issued a 2 percent general partner interest to Encore Energy Partners GP LLC for $12 and a 98 percent limited partner interest to Encore Partners LP Holdings LLC for $588. Each of these offerings was exempt from registration under Section 4(2) of the Securities Act of 1933 (the “Securities Act”).

On May 10, 2007, we issued 550,000 management incentive units to certain executive officers of our general partner in an offering exempt from registration under Section 4(2) of the Securities Act.

In connection with the closing of our initial public offering on September 17, 2007, we entered into a contribution agreement with our general partner, EAC, Encore Operating, Encore Partners LP Holdings LLC, and Encore Energy Partners Operating LLC. Pursuant to the contribution agreement, Encore Operating contributed the Permian Basin Assets to us in exchange for 4,043,478 common units and EAC agreed to indemnify us 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. The issuance of the common units was exempt from registration under Section 4(2) of the Securities Act.

47

ENCORE ENERGY PARTNERS LP

ITEM 6.   SELECTED FINANCIAL DATA

The following table shows selected historical financial data for the periods and as of the periods indicated. The selected historical financial data as of December 31, 2007, 2006, and 2005 and for the years ended December 31, 2007, 2006, 2005, and 2004 is derived from our audited financial statements. The selected historical financial data as of December 31, 2004 and 2003 and for the year ended December 31, 2003 is derived from unaudited financial statements.

The following selected consolidated financial and operating data should be read in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Item 8. Financial Statements and Supplementary Data”:

	Year Ended December 31,(a)
	2007			2006			2005		2004		2003
	(In thousands, except per unit data)
Consolidated Statements of Operations Data:
Revenues:
Oil	$	58,836		$	409		$	535	$	442	$	366
Natural gas		12,269			12,337			16,366		12,791		12,708
Marketing and other(b)		8,582			—			—		—		—
Total revenues		79,687			12,746			16,901		13,233		13,074
Expenses:
Production:
Lease operations		13,920			1,673			1,751		1,604		1,431
Production, ad valorem, and severance taxes		8,571			1,226			1,473		1,195		1,174
Depletion, depreciation, and amortization		25,998			1,200			1,286		1,394		1,544
General and administrative(c)		10,707			631			572		477		441
Marketing(b)		6,673			—			—		—		—
Derivative fair value loss(d)		26,301			—			—		—		—
Other operating		762			246			263		202		120
Total expenses		92,932			4,976			5,345		4,872		4,710
Operating income (loss)		(13,245	)		7,770			11,556		8,361		8,364
Other income (expenses):
Interest(e)		(12,294	)		—			—		—		—
Other		196			—			—		—		—
Total other income (expenses)		(12,098	)		—			—		—		—
Income (loss) before income taxes		(25,343	)		7,770			11,556		8,361		8,364
Current income tax provision		(10	)		—			—		—		—
Deferred income tax (provision) benefit		12			(122	)		—		—		—
Net income (loss)	$	(25,341	)	$	7,648		$	11,556	$	8,361	$	8,364
Net loss allocation(f):
Limited partners’ interest in net loss	$	(18,617	)
General partner’s interest in net loss	$	(389	)
Net loss per common unit(f):
Basic	$	(0.78	)
Diluted		(0.78	)
Weighted average common units outstanding(f):
Basic		23,877
Diluted		23,877
Cash distributions per common unit	$	0.053

48

ENCORE ENERGY PARTNERS LP

	Year Ended December 31,(a)
	2007			2006			2005			2004			2003
	(In thousands, except per unit data)
Consolidated Statements of Cash Flows Data:
Net cash provided by (used in):
Operating activities	$	10,091		$	10,919		$	11,604		$	9,394		$	9,715
Investing activities		(337,396	)		(1,036	)		(2,180	)		(1,810	)		(1,737	)
Financing activities		327,308			(9,883	)		(9,424	)		(7,584	)		(7,978	)

	Year Ended December 31,(a)
	2007			2006		2005		2004		2003
Total Production Volumes:
Oil (MBbls)		1,053			7		10		12		13
Natural gas (MMcf)		1,869			1,796		2,004		2,074		2,297
Combined (MBOE)		1,365			306		344		357		396
Average Realized Prices:
Oil ($/Bbl)	$	55.85		$	62.18	$	53.29	$	38.26	$	29.00
Natural gas ($/Mcf)		6.56			6.87		8.17		6.17		5.53
Combined ($/BOE)		52.09			41.67		49.13		37.05		33.06
Average Costs per BOE:
Lease operations	$	10.20		$	5.47	$	5.09	$	4.49	$	3.62
Production, ad valorem, and severance taxes		6.28			4.01		4.28		3.35		2.97
Depletion, depreciation, and amortization		19.05			3.92		3.74		3.90		3.90
General and administrative		7.84			2.06		1.66		1.34		1.11
Derivative fair value loss		19.27			—		—		—		—
Other operating expense		0.56			0.80		0.76		0.57		0.30
Marketing gain		(1.40	)		—		—		—		—
Proved Reserves:
Oil (MBbls)		14,417			50		45		43		46
Natural gas (MMcf)		39,141			37,426		44,190		40,966		43,875
Combined (MBOE)		20,940			6,288		7,410		6,871		7,359

	As of December 31,(a)
	2007		2006		2005		2004		2003
	(In thousands)
Consolidated Balance Sheets Data:
Working capital	$	3,144	$	1,633	$	3,505	$	2,257	$	1,890
Total assets		390,079		26,923		29,133		26,794		25,641
Long-term debt		47,500		—		—		—		—
Partners’/Owner’s equity		298,136		25,719		27,954		25,822		25,045

(a)	We acquired the Elk Basin Assets in March 2007. The operating results of these properties are included in our Consolidated Statements of Operations from the date of acquisition forward.
(b)	In March 2007, we acquired a crude oil pipeline and a natural gas pipeline as part of the Elk Basin acquisition.
(c)	As a result of becoming a publicly traded entity in September 2007, we incur additional expenses such as fees associated with annual and quarterly reports to unitholders, tax returns and Schedule K-1 preparation

49

ENCORE ENERGY PARTNERS LP

	and distribution, investor relations, registrar and transfer agent fees, incremental insurance costs, and accounting and legal services. In addition, pursuant to the administrative services agreement with Encore Operating, Encore Operating receives $1.75 per BOE of our production for performing all of our administrative services and reimbursement of actual third-party expenses incurred on our behalf.
(d)	In conjunction with the closing of the Elk Basin acquisition in March 2007, EAC contributed floor contracts to us and we purchased additional derivative contracts based on our hedging strategy. Prior to these purchases, we did not have any derivative contracts and, therefore, we did not have any costs related to derivative transactions.
(e)	In conjunction with the closing of the Elk Basin acquisition in March 2007, we entered into two credit agreements to fund a portion of the purchase price. Prior to the acquisition, we did not have any indebtedness and, therefore, we did not have any interest expense.
(f)	Prior to the closing of the IPO, EAC owned all of our general and limited partner interests, with the exception of management incentive units owned by certain executive officers of our general partner. Accordingly, earnings per unit is not presented for periods prior to the IPO. For additional information regarding earnings per unit, please read Note 8 of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data.”

50

ENCORE ENERGY PARTNERS LP

ITEM 7.   MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

Introduction

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

•  Overview of Business

•  2008 Outlook

•  Factors Affecting Comparability of Future Results

•  Results of Operations

—  Comparison of 2007 to 2006

—  Comparison of 2006 to 2005

•  Liquidity and Capital Resources

•  Capital Commitments and Contingencies

•  Off-Balance Sheet Arrangements

•  Inflation and Changes in Prices

•  Critical Accounting Policies and Estimates

•  New Accounting Pronouncements

•  Information Concerning Forward-Looking Statements

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. Our properties located in the Williston Basin of North Dakota and certain properties located in the Permian Basin of West Texas were acquired from Encore Operating, a wholly owned subsidiary of EAC, in February 2008. See “2008 Outlook” below for details regarding this acquisition. Information regarding reserves, well counts, and other operating and financial information presented in this Report does not include information attributable to the Permian and Williston Basin properties acquired in February 2008, unless otherwise indicated.

51

ENCORE ENERGY PARTNERS LP

From our date of formation to the closing of the initial public offering, our oil and natural gas properties consisted of the Elk Basin Assets, which were purchased in March 2007. The purchase price for the Elk Basin Assets was approximately $330.7 million, including estimated transaction costs of approximately $1.1 million.

On September 17, 2007, we completed our initial public offering of 9,000,000 common units at a price to the public of $21.00 per unit. On October 11, 2007, the underwriters exercised their option to purchase an additional 1,148,400 common units. Net proceeds from the issuance of common units, including the underwriters’ over-allotment option, were approximately $193.5 million, after deducting the underwriters’ discount and a structuring fee of approximately $14.9 million, in the aggregate, and offering expenses of approximately $4.7 million. The net proceeds were used to repay in full $126.4 million, including accrued interest, of outstanding indebtedness under a subordinated term loan from EAP Operating, Inc. and $65.9 million of outstanding indebtedness under our revolving credit facility.

Upon the closing of the initial public offering, 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. As a result of the initial public offering and the transactions entered into in conjunction therewith, our future results will differ materially from our historical results. For more information, please read “Factors Affecting Comparability of Future Results” below.

At December 31, 2007, our oil and natural gas properties had estimated total proved reserves of 14.4 MMBbls of oil and 39.1 Bcf of natural gas, based on December 31, 2007 spot market prices of $96.01 per Bbl of oil and $7.47 per Mcf of natural gas. On a BOE basis, our proved reserves were 20.9 MMBOE at December 31, 2007, of which approximately 69 percent was oil and approximately 86 percent was classified as proved developed. Based on our December 31, 2007 total proved reserves and annualized fourth quarter 2007 production, our average reserve-to-production ratio is approximately 13.5 years.

Our financial results and ability to generate cash depend upon many factors, particularly the price of oil and natural gas. Oil prices continued to strengthen in 2007, with average NYMEX prices increasing in each of the past three years. Natural gas prices continued to deteriorate in 2007 from record levels in 2005, but average NYMEX prices remain higher than historical averages. However, our natural gas wellhead differentials to NYMEX in 2007 remained consistent with 2006 as we realized 96 percent of the average NYMEX natural gas price. See additional analysis of our differentials for 2007, 2006, and 2005 in “Results of Operations” below. Commodity prices are influenced by many factors that are outside our control. We cannot accurately predict future commodity prices. For this reason, we attempt to mitigate the effect of fluctuating commodity prices by entering into commodity derivative contracts for a portion of our estimated future production.

2008 Outlook

On December 27, 2007, we entered into a purchase and investment agreement with Encore Operating to acquire certain oil and natural gas producing properties and related assets in the Permian and Williston Basins for total consideration of $250.4 million, subject to customary adjustments. The transaction closed on February 7, 2008 and was effective January 1, 2008. The total consideration consisted of $125.4 million in cash and 6,884,776 common units representing limited partner interests in us.

For 2008, the board of directors of our general partner has approved a $10.3 million capital budget for oil and natural gas related activities, consisting of $10.0 million for development and exploitation and $0.3 million for leasehold acreage. We expect to fund our 2008 capital expenditures with cash flow from operations. Including the Permian and Williston Basin properties acquired, we expect to maintain production over the long-term with maintenance capital expenditures of approximately $13.7 million per year.

The prices we receive for oil and natural gas production are largely based on current market prices, which are beyond our control. For comparability and accountability, we take a constant approach to budgeting

52

ENCORE ENERGY PARTNERS LP

commodity prices. We presently analyze our inventory of capital projects based on current NYMEX strip prices. If NYMEX prices trend downward for a sustained period of time, we may reevaluate our capital projects. The price risk on a substantial portion of our estimated future oil production is currently mitigated using commodity derivative contracts through December 2011, and a substantial portion of our estimated future natural gas production is currently mitigated using derivative contracts through December 2010. We intend to continue to enter into commodity derivative transactions to mitigate the impact of price volatility on our oil and natural gas revenues.

Oil prices have increased significantly since the beginning of 2005. Rising prices contributed to an increase in our oil revenues in 2007 compared to 2006. We anticipate a continued favorable commodity price environment in 2008. Significant factors that will impact near-term commodity prices include the following:

•  political developments in Iraq, Iran, Venezuela, Nigeria, and other oil-producing countries;

•  the extent to which members of OPEC and other oil exporting nations are able to manage oil supply through export quotas;

•  Russia’s increasing position as a major supplier of natural gas to world markets;

•  continued economic growth in China, India, and other developing countries;

•  concerns that major oil fields throughout the world have reached peak production;

•  low interest rates that are fueling continued economic expansion;

•  rising oilfield service costs;

•  the potential for terrorist activity; and

•  a fall in the value of the U.S. dollar relative to other currencies.

We expect to continue to pursue asset acquisitions in 2008, but expect to confront intense competition for these assets from third parties. Moreover, EAC is not prohibited from competing with us and constantly evaluates acquisitions and dispositions that do not involve us.

53

ENCORE ENERGY PARTNERS LP

Factors Affecting Comparability of Future Results

The discussion of our financial condition and results of operations that follows should be read in conjunction with our historical financial statements included elsewhere in this Report. Our future results could differ materially from our historical results due to a variety of factors, including the following:

No Comparative Results for Our Elk Basin Assets for the Two Years Ended December 31, 2006.  The discussion of our historical results that follows reflects the operations related to our Elk Basin Assets, only from March 7, 2007, the date of acquisition. The following table sets forth historical revenues and direct operating expenses attributable to the Elk Basin Assets for the periods indicated, as derived from Anadarko’s historical accounting records:

	Year Ended December 31,
	2006		2005
	(In thousands)
Revenues:
Oil	$	63,695	$	54,592
Natural gas		2,395		1,828
Marketing and other		3,649		1,745
Total revenues		69,739		58,165
Direct operating expenses:
Lease operating expenses		7,435		6,263
Marketing and other		5,598		3,909
Production and other taxes		7,839		6,769
Total direct operating expenses		20,872		16,941
Excess of revenues over direct operating expenses	$	48,867	$	41,224

The statements of revenues less direct operating expenses for the Elk Basin Assets may not be indicative of future results.

Increase in Outstanding Indebtedness.  For the two years ended December 31, 2006, we did not have any indebtedness and, therefore, we did not have any interest expense. In order to fund a portion of the purchase price for the Elk Basin Assets in March 2007, we borrowed $120 million from a wholly owned subsidiary of EAC pursuant to a subordinated term loan and $115 million under our revolving credit facility (excluding $1.7 million of debt issuance costs). Interest expense for 2007 was $12.3 million, of which $5.9 million related to our revolving credit facility and $6.4 million related to the subordinated term loan. The weighted average interest rate for all long-term debt in 2007 was 8.5 percent. We used a portion of the net proceeds from our initial public offering and the underwriters’ exercise of the over-allotment option to repay in full $126.4 million, including accrued interest, of outstanding indebtedness under the subordinated term loan and $65.9 million of outstanding borrowings under our revolving credit facility. At December 31, 2007, we had total long-term debt of $47.5 million under our revolving credit facility. In connection with the February 2008 purchase of the Permian and Williston Basin properties from EAC, we financed the $125.4 million cash portion of the purchase price through additional borrowings under our revolving credit facility. As a result, at February 25, 2008, we had total long-term debt of $169.5 million under our revolving credit facility.

Purchase of Derivatives.  The consolidated financial statements for the two years ended December 31, 2006 do not contain any costs related to derivative transactions. In connection with the acquisition of the Elk Basin Assets, Encore Operating purchased floor contracts for 2,500 Bbls/D of production at $65.00 per Bbl for April 2007 through December 2008 that were all later contributed to us at their fair market value on the date of transfer of $9.4 million. In addition to these contributed derivatives, we have since purchased additional

54

ENCORE ENERGY PARTNERS LP

derivative financial instruments as part of our risk management strategy. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” for discussion regarding our risk management strategy and derivative positions as of December 31, 2007.

Increase in Equity-Based Compensation Expense.  In May 2007, the board of directors of our general partner, with the approval of EAC’s Board of Directors and its compensation committee, granted management incentive units to certain executive officers of our general partner. A management incentive unit is a limited partner interest in our partnership that entitles the holder to quarterly distributions to the extent paid to our common unitholders, and to increasing distributions upon the achievement of 10 percent compounding increases in our annualized distribution rate to common unitholders, subject to a maximum limit on the aggregate distributions payable to holders of management incentive units. The management incentive units vest in three equal installments. The first installment vested upon the closing of the initial public offering, and the subsequent vesting will occur on the first and second anniversary of such closing date. For 2007, we recognized compensation expense of $6.8 million related to these management incentive units, which is included in “General and administrative expense” in the accompanying Consolidated Statement of Operations.

Additional General and Administrative Expenses.  As a result of being a publicly traded entity, we incur additional incremental general and administrative expenses associated with annual and quarterly reports to unitholders, tax returns and Schedule K-1 preparation and distribution, investor relations, registrar and transfer agent fees, incremental insurance costs, accounting, and legal services. These incremental general and administrative expenses were not incurred and thus are not reflected in the consolidated financial statements for periods prior to September 17, 2007, the closing date of our initial public offering.

55

ENCORE ENERGY PARTNERS LP

Results of Operations

Comparison of 2007 to 2006

Oil and natural gas revenues and production.  The following table illustrates the primary components of our oil and natural gas revenues for 2007 and 2006, as well as each year’s respective oil and natural gas production volumes and average prices:

	Year Ended December 31,				Increase/
	2007		2006		(Decrease)
	(In thousands)
Revenues:
Oil	$	58,836	$	409	$	58,427
Natural gas		12,269		12,337		(68	)
Total combined oil and natural gas revenues	$	71,105	$	12,746	$	58,359
Averaged realized prices:
Oil ($/Bbl)	$	55.85	$	62.18	$	(6.33	)
Natural gas ($/Mcf)	$	6.56	$	6.87	$	(0.31	)
Combined (BOE)	$	52.09	$	41.67	$	10.42
Total production volumes:
Oil (MBbls)		1,053		7		1,046
Natural gas (MMcf)		1,869		1,796		73
Combined (MBOE)		1,365		306		1,059
Average daily production volumes:
Oil (Bbl/D)		3,440		18		3,422
Natural gas (Mcf/D)		5,272		4,920		352
Combined (BOE/D)		4,318		838		3,480
Average NYMEX prices:
Oil (per Bbl)	$	72.39	$	66.22	$	6.17
Natural gas (per Mcf)	$	6.86	$	7.18	$	(0.32	)

Oil revenues increased $58.4 million from $0.4 million in 2006 to $58.8 million in 2007. The increase is primarily due to an increase in oil production volumes of 1,046 MBbls, which contributed approximately $65.1 million in additional oil revenues, partially offset by lower average realized oil prices, which negatively impacted oil revenues by approximately $6.7 million. The increase in oil production volumes is due to our acquisition of the Elk Basin Assets in March 2007. Despite higher average NYMEX crude oil prices in 2007 compared to 2006, our average realized oil price decreased $6.33 per Bbl in 2007 compared to 2006. Differentials for oil production from our Elk Basin Assets are wider than oil differentials from the Permian Basin Assets. In 2007, approximately 99 percent of our oil production was from our Elk Basin Assets, which sells at a higher discount to NYMEX due to the quality of the crude oil, which is a heavy, sour crude, as well as its location relative to markets in the Rocky Mountains.

Natural gas revenues decreased slightly from 2006 to $12.3 million in 2007. Natural gas revenues declined as a result of a reduction in our average realized natural gas price; however, the decrease in the average realized price was offset by an increase in production volumes of 73 MMcf from our Elk Basin acquisition.

56

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 2007 and 2006. Management uses the realized price to NYMEX margin analysis to analyze trends in our oil and natural gas revenues.

	Year Ended December 31,
	2007			2006
Average realized oil price ($/Bbl)	$	55.85		$	62.18
Average NYMEX ($/Bbl)	$	72.39		$	66.22
Differential to NYMEX	$	(16.54	)	$	(4.04	)
Average realized oil price to NYMEX percentage		77	%		94	%
Average realized natural gas price ($/Mcf)	$	6.56		$	6.87
Average NYMEX ($/Mcf)	$	6.86		$	7.18
Differential to NYMEX	$	(0.30	)	$	(0.31	)
Average realized natural gas price to NYMEX percentage		96	%		96	%

In 2007, our average realized oil price as a percentage of the average NYMEX price decreased to 77 percent from 94 percent in 2006. The differential widened due to our Elk Basin acquisition, as approximately 99 percent of our oil production in 2007 was from our Elk Basin Assets. The oil production from our Elk Basin Assets sells at a higher discount to NYMEX as compared to our Permian Basin Assets due to continued production increases from competing Canadian and Rocky Mountain producers, limited refining and pipeline capacity in the Rocky Mountain area, corresponding steep pricing discounts by regional refiners, and the quality of the Elk Basin oil. We expect our oil differentials to tighten in the first quarter of 2008 as compared to the fourth quarter 2007 differential of $25.26 per Bbl due to the acquisition of certain oil and natural gas producing properties and related assets in the Permian and Williston Basins from Encore Operating, which have historically sold at a lower differential to NYMEX than our Elk Basin Assets. See additional discussion of the acquisition of the Permian and Williston Basin properties in “2008 Outlook” above.

In 2007, our average realized natural gas price as a percentage of the average NYMEX price remained consistent with 2006 at 96 percent. In 2007, approximately 85 percent of our natural gas production was from our Permian Basin Assets. We expect our natural gas differentials to remain flat in the first quarter of 2008 as compared to the fourth quarter 2007 positive differential of $0.22 per Mcf.

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. We did not have any marketing revenues or expenses in 2006. The following table summarizes our marketing activities for 2007 (in thousands, except per BOE amounts):

Marketing revenues	$	8,582
Marketing expenses		(6,673	)
Marketing, net	$	1,909
Marketing revenues per BOE	$	6.29
Marketing expenses per BOE		(4.89	)
Marketing, net per BOE	$	1.40

57

ENCORE ENERGY PARTNERS LP

Expenses.  The following table summarizes our expenses, excluding marketing expenses shown above, for 2007 and 2006:

	Year Ended December 31,					Increase/
	2007			2006		(Decrease)
	(In thousands)
Expenses:
Production:
Lease operations	$	13,920		$	1,673	$	12,247
Production, ad valorem, and severance taxes		8,571			1,226		7,345
Total production expenses		22,491			2,899		19,592
Other:
Depletion, depreciation, and amortization		25,998			1,200		24,798
Derivative fair value loss		26,301			—		26,301
General and administrative		10,707			631		10,076
Other operating		762			246		516
Total operating		86,259			4,976		81,283
Interest		12,294			—		12,294
Income tax (benefit) provision		(2	)		122		(124	)
Total expenses	$	98,551		$	5,098	$	93,453
Expenses (per BOE):
Production:
Lease operations	$	10.20		$	5.47	$	4.73
Production, ad valorem, and severance taxes		6.28			4.01		2.27
Total production expenses		16.48			9.48		7.00
Other:
Depletion, depreciation, and amortization		19.05			3.92		15.13
General and administrative		7.84			2.06		5.78
Derivative fair value loss		19.27			—		19.27
Other operating		0.56			0.80		(0.24	)
Total operating		63.20			16.26		46.94
Interest		9.01			—		9.01
Income tax provision (benefit)		—			0.40		(0.40	)
Total expenses	$	72.21		$	16.66	$	55.55

Production expenses.  Total production expenses increased $19.6 million from $2.9 million in 2006 to $22.5 million in 2007. This increase resulted from an increase in total production volumes, primarily associated with our Elk Basin acquisition, as well as a $7.00 increase in production expenses per BOE. Our production margin in 2007 increased to $48.6 million as compared to $9.8 million in 2006. On a per BOE basis, our production margin increased 11 percent to $35.61 per BOE as compared to $32.19 per BOE in 2006.

The production expense attributable to LOE increased $12.2 million from $1.7 million in 2006 to $13.9 million in 2007, primarily due to a $4.73 increase in the per BOE rate, which contributed approximately $6.5 million of additional LOE, and an increase in production volumes, which contributed approximately $5.8 million of 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 the Permian Basin Assets.

58

ENCORE ENERGY PARTNERS LP

The production expense attributable to production, ad valorem, and severance taxes (“production taxes”) increased $7.3 million from $1.2 million in 2006 to $8.6 million in 2007. The increase is due to higher oil and natural gas revenues resulting from our Elk Basin acquisition and higher tax rates in the Elk Basin region as compared to the Permian Basin properties. As a percentage of oil and natural gas revenues, production taxes increased to 12 percent in 2007 as compared to 10 percent in 2006.

Depletion, depreciation, and amortization (“DD&A”) expense.  DD&A expense increased $24.8 million from $1.2 million in 2006 to $26.0 million in 2007 due to an increase in the per BOE rate of $15.13 and increased production volumes resulting from our Elk Basin acquisition. The increase in the per BOE rate was due to the higher acquisition price of proved reserves at Elk Basin as compared to the Permian Basin Assets, which were acquired when oil and natural gas commodity prices were significantly lower.

General and administrative (“G&A”) expense.  G&A expense increased $10.1 million from $0.6 million in 2006 to $10.7 million in 2007 primarily due to compensation expense recognized for management incentive units in 2007 and G&A expenses of $1.75 per BOE under the administrative services agreement with Encore Operating. In 2007, we recognized compensation expense of $6.8 million related to management incentive units and $3.3 million of expense (including COPAS recovery) under the administrative services agreement.

Derivative fair value loss.  During 2007, we recorded a $26.3 million derivative fair value loss, of which $23.5 million related to mark-to-market losses and $4.1 million related to premium amortization, offset by $1.2 million of cash receipts related to settlements on our commodity derivative contracts. There were no such derivative instruments in place during 2006.

Other operating expense.  Other operating expense increased $0.5 million from $0.2 million in 2006 to $0.8 million in 2007. The increase is primarily due to transportation expenses for our oil production.

Interest expense.  In March 2007, we borrowed $115 million under our revolving credit facility (excluding debt issuance costs of $1.7 million) and $120 million under a subordinated credit agreement with EAP Operating, Inc., a wholly owned subsidiary of EAC. The funds from these borrowings were used to finance our Elk Basin acquisition. Interest expense was $12.3 million in 2007, of which $5.9 million related to our revolving credit facility and $6.4 million related to our subordinated credit agreement. We did not have any interest expense in 2006. The weighted average interest rate for all long-term debt in 2007 was 8.5 percent.

59

ENCORE ENERGY PARTNERS LP

Comparison of 2006 to 2005

Oil and natural gas revenues and production.  The following table illustrates the primary components of our oil and natural gas revenues for 2006 and 2005, as well as each year’s respective oil and natural gas production volumes and average prices:

	Year Ended December 31,				Increase/ (Decrease)
	2006		2005		$			%
	(In thousands)
Revenues:
Oil	$	409	$	535	$	(126	)		(24	)%
Natural gas		12,337		16,366		(4,029	)		(25	)%
Total combined oil and natural gas revenues	$	12,746	$	16,901	$	(4,155	)		(25	)%
Average realized prices:
Oil ($/Bbl)	$	62.18	$	53.29	$	8.89			17	%
Natural gas ($/Mcf)	$	6.87	$	8.17	$	(1.30	)		(16	)%
Combined ($/BOE)	$	41.67	$	49.13	$	(7.46	)		(15	)%
Total production volumes:
Oil (MBbls)		7		10		(3	)		(30	)%
Natural gas (MMcf)		1,796		2,004		(208	)		(10	)%
Combined (MBOE)		306		344		(38	)		(11	)%
Average daily production volumes:
Oil (Bbl/D)		18		28		(10	)		(36	)%
Natural gas (Mcf/D)		4,920		5,490		(570	)		(10	)%
Combined (BOE/D)		838		942		(104	)		(11	)%
Average NYMEX prices:
Oil ($/Bbl)	$	66.22	$	56.56	$	9.66			17	%
Natural gas ($/Mcf)	$	7.18	$	8.81	$	(1.63	)		(19	)%

Oil revenues decreased $0.1 million from $0.5 million in 2005 to $0.4 million in 2006. The decrease was due primarily to lower oil production volumes of 3 MBbls, which reduced revenues by approximately $0.2 million, partially offset by higher realized average oil prices, which contributed approximately $0.1 million in additional oil revenues. In 2006, we did not develop new oil wells on our properties. Accordingly, we experienced normal production declines and, as a result, production volumes decreased for oil. The higher realized average oil price was the result of increases in the overall market price for oil as reflected in the increase in the average NYMEX price from $56.56 per Bbl in 2005 to $66.22 per Bbl in 2006.

Natural gas revenues decreased $4.0 million from $16.4 million in 2005 to $12.3 million in 2006. The decrease was primarily due to lower average realized natural gas prices, which reduced revenues by approximately $2.3 million, and lower natural gas production volumes of 208 MMcf, which reduced revenues by approximately $1.7 million. In 2006, only three new natural gas wells were drilled on our properties. The natural gas production from those wells was not sufficient to offset the normal production declines and, as a result, production volumes decreased. The lower average realized natural gas price was due to a decrease in the overall market price of natural gas as reflected in the decrease in the average NYMEX price from $8.81 per Mcf in 2005 to $7.18 per Mcf in 2006.

60

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 2006 and 2005. Management uses the realized price to NYMEX margin analysis to analyze trends in our oil and natural gas revenues.

	Year Ended December 31,
	2006			2005
Average realized oil price ($/Bbl)	$	62.18		$	53.29
Average NYMEX ($/Bbl)	$	66.22		$	56.56
Differential to NYMEX	$	(4.04	)	$	(3.27	)
Average realized oil price to NYMEX percentage		94	%		94	%
Average realized natural gas price ($/Mcf)	$	6.87		$	8.17
Average NYMEX ($/Mcf)	$	7.18		$	8.81
Differential to NYMEX	$	(0.31	)	$	(0.64	)
Average realized natural gas price to NYMEX percentage		96	%		93	%

Expenses.  The following table summarizes our expenses for 2006 and 2005:

	Year Ended December 31,				Increase/ (Decrease)
	2006		2005		$			%
	(In thousands)
Expenses:
Production:
Lease operations	$	1,673	$	1,751	$	(78	)
Production, ad valorem, and severance taxes		1,226		1,473		(247	)
Total production expenses		2,899		3,224		(325	)		(10	)%
Other:
Depletion, depreciation, and amortization		1,200		1,286		(86	)
General and administrative		631		572		59
Other operating		246		263		(17	)
Total operating		4,976		5,345		(369	)		(7	)%
Deferred income tax provision		122		—		122
Total expenses	$	5,098	$	5,345	$	(247	)		(5	)%
Expenses (per BOE):
Production:
Lease operations	$	5.47	$	5.09	$	0.38
Production, ad valorem, and severance taxes		4.01		4.28		(0.27	)
Total production expenses		9.48		9.37		0.11			1	%
Other:
Depletion, depreciation, and amortization		3.92		3.74		0.18
General and administrative		2.06		1.66		0.40
Other operating		0.80		0.76		0.04
Total operating		16.26		15.53		0.73			5	%
Deferred income tax provision		0.40		—		0.40
Total expenses	$	16.66	$	15.53	$	1.13			7	%

61

ENCORE ENERGY PARTNERS LP

Production expenses.  Total production expenses decreased $0.3 million from $3.2 million in 2005 to $2.9 million in 2006. This decrease resulted from lower total production volumes. Total production expenses per BOE remained virtually unchanged while combined oil and natural gas average realized prices decreased approximately 15 percent. As a result of these changes, our production margin for 2006 decreased approximately 19 percent to $32.19 per BOE as compared to $39.76 per BOE for 2005.

The production expense attributable to LOE for 2006 decreased $0.1 million from $1.8 million in 2005 to $1.7 million in 2006. The decrease was due to lower production volumes, which reduced LOE by approximately $0.2 million, partially offset by an increase in the per BOE rate, which contributed approximately $0.1 million of additional LOE. The increase in our average LOE per BOE rate of $0.38 was attributable to:

•  increases in prices paid to oilfield service companies and suppliers due to a higher price environment;

•  increased operational activity to enhance production;

•  the operation of higher operating cost wells (which offered acceptable rates of return due to increased oil and natural gas prices);

•  higher salary levels for engineers and other technical professionals; and

•  increased stock-based compensation expense relating to equity grants to employees of EAC.

The production expense attributable to production taxes decreased $0.2 million from $1.5 million in 2005 to $1.2 million in 2006. The decrease was due to lower production volumes. As a percentage of oil and natural gas revenues, production taxes increased approximately one percent in 2006 as compared to 2005.

DD&A expense.  DD&A expense decreased $0.1 million from $1.3 million in 2005 to $1.2 million in 2006 due to lower production volumes.

G&A expense.  G&A expense remained virtually unchanged in 2006 as compared to 2005. The $0.40 increase in the per BOE rate was primarily the result of the adoption of SFAS No. 123 (revised 2004), “Share-Based Payment” (“SFAS 123R”) on January 1, 2006, which resulted in expensing stock options granted to employees of EAC.

Income taxes.  Income tax expense for 2006 increased $0.1 million over 2005. This was due to the enactment of the Texas Margin Tax, which caused us to adjust our net deferred tax balances using the new higher marginal tax rate we expected to be effective when those deferred taxes become current. This resulted in a charge of $0.1 million during 2006. The effective tax rate for the Texas Margin Tax is up to 0.7 percent on the portion of our income that is apportioned to Texas, beginning with tax reports due on or after January 1, 2008.

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 our available cash. In making cash distributions, our general partner attempts to avoid large variations in the amount we distribute from quarter to quarter. In order to facilitate this, our partnership agreement permits our general partner to establish cash reserves to be used to pay distributions for any one or more of the next four quarters. In addition, our partnership agreement allows our general partner to borrow funds to make distributions.

Because of the seasonal nature of oil and natural gas prices, we may borrow in order to level out our distributions during the year. In addition, we mitigate the price risk on a substantial portion of our production

62

ENCORE ENERGY PARTNERS LP

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 oil and 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 derivatives, 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. If this were to occur, we may make working capital borrowings to fund our distributions. 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 flow from operations and issuances of debt and equity.

If cash flow from operations does not meet our expectations, we may reduce the expected level of capital expenditures and/or fund a portion of the expenditures using borrowings under our revolving credit facility, issuances of debt and equity securities, or from other sources. Funding our capital program from sources other than cash flow from operations could limit our ability to make acquisitions. In the event we make one or more acquisitions and the amount of capital required is greater than the amount we have available for acquisitions at that time, we would reduce the expected level of capital expenditures and/or seek additional capital. If we seek additional capital for that or other reasons, we may do so through traditional reserve base borrowings, joint venture partnerships, production payment financings, asset sales, offerings of debt or equity securities or other means. We cannot assure unitholders that needed capital will be available on acceptable terms or at all. Our ability to raise funds through the incurrence of additional indebtedness will be limited by covenants in our revolving credit facility. If we are unable to obtain funds when needed or on acceptable terms, we may not be able to complete acquisitions that may be favorable to us or finance the capital expenditures necessary to replace our reserves.

Please read “— Capital Commitments and Contingencies” below for information regarding our primary cash needs.

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 2007 decreased by 10 percent and 5 percent, respectively, as compared to 2006. These prices have historically fluctuated widely in response to changing market forces. For 2007, approximately 77 percent of our production was oil. To the extent oil and natural gas prices decline or we experience significant widening of our wellhead 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 wider than historical 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 unused availability under our revolving credit facility will be sufficient to fund our planned capital expenditures and distributions for the foreseeable future.

Cash flows provided by operating activities.  Cash provided by operating activities decreased $0.8 million from $10.9 million in 2006 to $10.1 million in 2007. The decrease was primarily due to an increase in accounts receivable as a result of increased oil and natural gas revenues, partially offset by an increase in corresponding accounts payable and accrued liabilities.

Cash provided by operating activities decreased $0.7 million from $11.6 million in 2005 to $10.9 million in 2006. Total oil and natural gas revenues in 2006 decreased $4.2 million, or 25 percent, from 2005, which was offset by an increase of $3.2 million in changes in operating assets and liabilities. The $4.2 million

63

ENCORE ENERGY PARTNERS LP

decrease in oil and natural gas revenues was primarily the result of a 10 percent decrease in natural gas volumes and a 19 percent decrease in the average natural gas price per Mcf.

Cash flows used in investing activities.  Cash used in investing activities increased $336.4 million from $1.0 million in 2006 to $337.4 million in 2007, primarily due to our Elk Basin acquisition.

Cash used in investing activities decreased $1.1 million from $2.2 million in 2005 to $1.0 million in 2006, which was wholly attributable to lower costs incurred for the development of oil and natural gas properties.

Cash flows provided by (used in) financing activities.  Our cash flows from financing activities consist primarily of proceeds from and payments on long-term debt, net proceeds received from the sale of common units in our initial public offering, and contributions received from EAC to partially finance our Elk Basin acquisition. During 2007, we received net cash of $327.3 million from financing activities, including net borrowings on our long-term debt of $45.8 million and net proceeds received from the sale of our common units of $193.5 million. In addition, we received a $93.7 million contribution from EAC to partially finance the acquisition of the Elk Basin Assets. Net cash provided from borrowings on our long-term debt and proceeds from the IPO were offset by $1.3 million in distributions to our unitholders in the fourth quarter of 2007 and distributions of $4.2 million to EAC prior to our IPO. During 2006, we used net cash of $9.9 million in financing activities for distributions of earnings to EAC.

Cash used in financing activities increased $0.5 million from $9.4 million in 2005 to $9.9 million in 2006, which was wholly attributable to an increase in distributions to EAC.

Revolving Credit Facility

Our principal source of short-term liquidity is our revolving credit facility, which matures on March 7, 2012.

In conjunction with the closing of the acquisition of the Elk Basin Assets on March 7, 2007, our operating company 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 our operating company from time to time and letters of credit to be issued from time to time for the account of the operating company 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 December 31, 2007, the borrowing base was $145 million. Upon completion of the acquisition of the Permian and Williston Basins as discussed above, the revolving credit facility borrowing base was increased to $240 million.

The credit agreement matures on March 7, 2012. The operating company’s obligations under the credit agreement are secured by a first-priority security interest in the operating company’s and its restricted subsidiaries’ proved oil and natural gas reserves and in the equity interests of the operating company and its restricted subsidiaries. In addition, the operating company’s obligations under the credit agreement are guaranteed by us and the operating company’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.

64

ENCORE ENERGY PARTNERS LP

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			Applicable Margin
Ratio of Total Outstanding Borrowings to Borrowing Base	for Eurodollar Loans			for 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 the operating company) 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.

As of December 31, 2007, the aggregate principal amount of loans outstanding under the credit agreement was $47.5 million and there were $0.1 million of outstanding letters of credit. 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 the operating company maintain a ratio of consolidated current assets to consolidated current liabilities of not less than 1.0 to 1.0;

•  a requirement that the operating company 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 the operating company 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 the operating company 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.

The operating company 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

65

ENCORE ENERGY PARTNERS LP

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 December 31, 2007, we had $47.5 million outstanding and $97.4 million available to borrow under our revolving credit facility. On February 25, 2008, we had $169.5 million outstanding and $70.4 million available to borrow under our revolving credit facility. The increase in outstanding indebtedness subsequent to year-end was due to the acquisition of the Permian and Williston Basin properties from EAC. We financed the $125.4 million cash portion of the purchase price through additional borrowings under our revolving credit facility.

Debt covenants.  At December 31, 2007, we were in compliance with all of our debt covenants.

Letters of credit.  At December 31, 2007 and February 25, 2008, we had $0.1 million outstanding letters of credit.

Subordinated Credit Agreement

On March 7, 2007, our operating company 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 us in the aggregate amount of $120 million. The total outstanding balance of $126.4 million, including accrued interest, was repaid using a portion of the net proceeds from the IPO.

Current capitalization.  At December 31, 2007, we had total assets of $390.1 million and total capitalization was $345.6 million, of which 86 percent was represented by partners’ equity and 14 percent by long-term debt. At December 31, 2006, we had total assets of $26.9 million and total capitalization was $25.7 million, all of which was represented by owner’s net equity. The percentages of our capitalization represented by partners’ equity and long-term debt could vary in the future if debt is used to finance future capital projects or potential acquisitions.

Capital Commitments and Contingencies

Our primary needs for cash are as follows:

•  Distributions to unitholders;

•  Development and exploitation of existing 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 fourth quarter 2007, we distributed $1.3 million to our unitholders with respect to the quarter ended September 30, 2007. The quarterly distribution of $0.053 per unit was based on an initial quarterly distribution of $0.35 per unit, prorated for the

66

ENCORE ENERGY PARTNERS LP

period from and including September 17, 2007 (the closing date of the initial public offering) through September 30, 2007.

On January 21, 2008, we declared a distribution with respect to the fourth quarter of 2007 to unitholders of record as of the close of business on February 6, 2008. The $9.8 million total distribution was paid on February 14, 2008 to unitholders at a rate of $0.3875 per unit.

Development and exploitation of existing oil and natural gas properties.  Our expenditures for development and exploitation investments primarily relate to drilling development and infill wells, workovers of existing wells, and field related facilities. Our development and exploitation capital for 2007 of $8.9 million yielded a total of 20 gross (6.5 net) successful wells.

Acquisitions of oil and natural gas properties.  On March 7, 2007, we acquired oil and natural gas properties in the Elk Basin for a purchase price of approximately $330.7 million, including $1.1 million of transaction costs.

Funding of necessary working capital.  At December 31, 2007, our working capital (defined as total current assets less total current liabilities) was $3.1 million while at December 31, 2006 our working capital was $1.6 million, an improvement of $1.5 million. At December 31, 2005, our working capital was $3.5 million. The improvement in 2007 was primarily attributable to an increase in accounts receivable as a result of increased oil and natural gas revenues due to our Elk Basin acquisition. The reduction of working capital in 2006 compared to 2005 was primarily due to decreases in the NYMEX price of natural gas, which caused a reduction in natural gas revenues and corresponding accounts receivable.

For 2008, we expect working capital to remain positive. Our production volumes, commodity prices, and our related differentials for oil and natural gas will be the largest variables affecting working capital. Our operating cash flow is determined in large part by production volumes and commodity prices. Assuming moderate to high commodity prices and constant or increasing production volumes, our operating cash flow should remain positive for 2008.

The board of directors of our general partner has approved a capital budget of approximately $10.3 million for 2008. The level of these and other future expenditures is largely discretionary, and the amount of funds devoted to any particular activity may increase or decrease significantly, depending on available opportunities, timing of projects, and market conditions. We plan to finance our ongoing expenditures using internally generated cash flow.

Contractual obligations.  The following table illustrates our contractual obligations outstanding at December 31, 2007:

	Payments Due by Period
Contractual Obligations and Commitments	Total		2008		2009-2010		2011-2012		Thereafter
	(In thousands)
Revolving credit facility(a)	$	59,830	$	2,959	$	5,919	$	50,952	$	—
Derivative obligations(b)		9,543		—		9,543		—		—
Development commitments(c)		2,247		2,247		—		—		—
Asset retirement obligations(d)		24,905		1,328		353		430		22,794
Total	$	96,525	$	6,534	$	15,815	$	51,382	$	22,794

(a)	Amounts include both principal and projected interest payments. Please read Note 6 of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information regarding our long-term debt.
(b)	Derivative obligations represent net liabilities for derivatives that were valued as of December 31, 2007, the ultimate settlement of which are unknown because they are subject to continuing market risk. Please read “Item 7A. Quantitative and Qualitative Disclosures about Market Risk” and Note 10 of Notes to

67

ENCORE ENERGY PARTNERS LP

	Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information regarding our derivative obligations.
(c)	Development commitments represent authorized purchases for work in process. Also at December 31, 2007, we had $2.8 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 5 of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information regarding our asset retirement obligations.

Other contingencies and commitments.  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 receives 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 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.

The administrative fee will increase in the following circumstances:

•  beginning on the first day of April in each year beginning on April 1, 2008 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.

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements that are material to our financial position or results of operations.

Inflation and Changes in Prices

Our oil and natural gas revenues, the value of our assets, and our ability to obtain bank loans or additional capital on attractive terms have been and will continue to be affected by changes in oil and natural gas prices. Historically, significant fluctuations have occurred in oil and natural gas prices. The following table indicates the average oil and natural gas prices we received for 2007, 2006, and 2005.

	Year Ended December 31,
	2007		2006		2005
Average Realized Price:
Oil ($/Bbl)	$	55.85	$	62.18	$	53.29
Natural gas ($/Mcf)		6.56		6.87		8.17
Combined ($/BOE)		52.09		41.67		49.13

68

ENCORE ENERGY PARTNERS LP

The increase in oil and natural gas prices may be accompanied by or result in: (i) increased development costs, as the demand for drilling operations continues to increase; (ii) increased severance taxes, as we are subject to higher severance taxes due to the increased value of oil and natural gas extracted from our wells; (iii) increased LOE due to increased demand for services related to the operation of our wells; and (iv) increased electricity costs. We believe our risk management program and available borrowing capacity under our revolving credit facility provide means for us to manage commodity price risks through our commodity derivative program.

Critical Accounting Policies and Estimates

The preparation of financial statements in accordance with U.S. generally accepted accounting principles requires management to make estimates and assumptions that affect reported amounts and related disclosures. Management considers an accounting estimate to be critical if it requires assumptions to be made that were uncertain at the time the estimate was made, and changes in the estimate or different estimates that could have been selected, could have a material impact on our consolidated results of operations or financial condition. Management has identified the following critical accounting policies and estimates.

Oil and Natural Gas Properties

Successful efforts method.  We use the successful efforts method of accounting for oil and natural gas properties under SFAS No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies.” Under this method, all costs associated with productive and nonproductive development wells are capitalized. Exploration expenses, including geological and geophysical expenses and delay rentals, are charged to expense as incurred. Costs associated with drilling exploratory wells are initially capitalized pending determination of whether the well is economically productive or nonproductive.

If an exploratory well does not find reserves or does not find reserves in a sufficient quantity as to make them economically producible, the previously capitalized costs would be expensed in our Consolidated Statements of Operations and shown as a non-cash adjustment to net income in the “Operating activities” section of our Consolidated Statements of Cash Flows in the period in which the determination was made. If an exploratory well finds reserves but they cannot be classified as proved, we continue to capitalize the associated cost as long as the well has found a sufficient quantity of reserves to justify its completion as a producing well and we are making sufficient progress in assessing the reserves and the operating viability of the project. If subsequently we determine that neither of these conditions continues to exist, all previously capitalized costs associated with the exploratory well are expensed and shown as a non-cash adjustment to net income in the “Operating activities” section of our Consolidated Statements of Cash Flows in the period in which the determination was made. Re-drilling or directional drilling in a previously abandoned well is classified as development or exploratory based on whether it is in a proved or unproved reservoir. Expenditures for repairs and maintenance to sustain or increase production from the existing producing reservoir are charged to expense as incurred. Expenditures to recomplete a current well in a different unproved reservoir are capitalized pending determination that economic reserves have been added. If the recompletion is not successful, the expenditures are charged to expense. All capitalized costs associated with both development and exploratory wells are shown as “Development of oil and natural gas properties” in the “Investing activities” section of our Consolidated Statements of Cash Flows.

DD&A expense is directly affected by our reserve estimates. Any change in reserves directly impacts the amount of DD&A expense that we recognize in a given period. Assuming no other changes, such as an increase in depreciable base, as our reserves increase, the amount of DD&A expense in a given period decreases and vice versa. Changes in future commodity prices would likely result in increases or decreases in estimated recoverable reserves. DD&A expense associated with lease and well equipment and intangible drilling costs is based upon only proved developed reserves, while DD&A expense for capitalized leasehold costs is based upon total proved reserves. As a result, changes in the classification of our reserves could have a material impact on our DD&A expense. Miller & Lents estimates our reserves annually on December 31.

69

ENCORE ENERGY PARTNERS LP

Significant tangible equipment added or replaced is capitalized. Expenditures to construct facilities or increase the productive capacity from existing reservoirs are capitalized. Capitalized costs are amortized on a unit-of-production basis over the remaining life of total proved developed reserves or proved reserves, as applicable. Natural gas volumes are converted to BOE at the rate of six Mcf to one Bbl of oil. Significant revisions to reserve estimates can be and are made by our reserve engineers each year. Mostly these are the result of changes in price, but as reserve quantities are estimates, they can also change as more or better information is collected, especially in the case of estimates in newer fields. Downward revisions have the effect of increasing our DD&A rate, while upward revisions have the effect of decreasing our DD&A rate.

The costs of retired, sold, or abandoned properties that constitute part of an amortization base are charged or credited, net of proceeds received, to the accumulated DD&A reserve. Gains or losses from the disposal of other properties are recognized in the current period.

In accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” an impairment of capitalized costs of long-lived assets to be held and used, including proved oil and natural gas properties, must be assessed whenever events and circumstances indicate that the carrying value of the asset may not be recoverable. If impairment is indicated based on a comparison of the asset’s carrying value to its undiscounted expected future net cash flows, then an impairment charge is recognized to the extent that the asset’s carrying value exceeds its fair value. Expected future net cash flows are based on existing proved reserve and production information and pricing assumptions that management believes are reasonable. Any impairment charge incurred is expensed and reduces our recorded basis in the asset. Management currently aggregates proved property for impairment testing the same way as for calculating DD&A. The price assumptions used to calculate undiscounted cash flows is based on judgment. We use prices consistent with the prices used in bidding on acquisitions and/or assessing capital projects. These price assumptions are critical to the impairment analysis as lower prices could trigger impairment while higher prices would have the opposite effect.

Oil and natural gas reserves.  Our estimates of proved reserves are based on the quantities of oil and natural gas that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. Miller and Lents prepares a reserve and economic evaluation of all of our properties on a well-by-well basis. Assumptions used by Miller and Lents in calculating reserves or regarding the future cash flows or fair value of our properties are subject to change in the future. The accuracy of reserve estimates is a function of:

•  the quality and quantity of available data;

•  the interpretation of that data;

•  the accuracy of various mandated economic assumptions; and

•  the judgment of the independent reserve engineer.

Future prices received for production and future production costs may vary, perhaps significantly, from the prices and costs assumed for purposes of calculating reserve estimates. We may not be able to develop proved reserves within the periods estimated. Furthermore, prices and costs may not remain constant. Actual production may not equal the estimated amounts used in the preparation of reserve projections. As these estimates change, calculated reserves change. Any change in reserves directly impacts our estimate of future cash flows from the property, the property’s fair value, and our depletion rate.

Asset retirement obligations.  In accordance with SFAS No. 143, “Accounting for Asset Retirement Obligations,” we estimate our eventual obligations associated with the retirement of tangible long-lived assets that result from the acquisition, construction, and development of our oil and natural gas wells and related facilities. We recognize the fair value of a liability for an asset retirement obligation in the period in which the liability is incurred. For oil and natural gas properties, this is the period in which an oil or natural gas property is acquired or a new well is drilled. An amount equal to and offsetting the liability is capitalized as part of the

70

ENCORE ENERGY PARTNERS LP

carrying amount of our oil and natural gas properties at its discounted fair value. The liability is then accreted up by recording expense each period until it is settled or the well is sold, at which time the liability is reversed.

The fair value of the liability associated with the asset retirement obligation is determined using significant assumptions, including current estimates of the plugging and abandonment costs, annual expected inflation of these costs, the productive life of the asset, and our credit-adjusted risk-free interest rate used to discount the expected future cash flows. Changes in any of these assumptions can result in significant revisions to the estimated asset retirement obligation. Revisions to the obligation are recorded with an offsetting change to the carrying amount of the related oil and natural gas properties, resulting in prospective changes to DD&A and accretion expense. Because of the subjectivity of assumptions and the relatively long life of most of our oil and natural gas properties, the costs to ultimately retire these assets may vary significantly from our estimates.

Revenue Recognition

Revenues are recognized for jointly owned properties as oil and natural gas is produced and sold, net of royalties. Natural gas revenues are also reduced by any processing and other fees paid except for transportation costs paid to third parties, which are recorded as expense. Natural gas revenues are recorded using the sales method of accounting whereby revenue is recognized based on our actual sales of natural gas rather than our share of natural gas production. Royalties and severance taxes are paid based upon the actual price received from the sales. To the extent actual quantities and values of oil and natural gas are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volumes and price for those properties are estimated and recorded. If our overproduced imbalance position (i.e., we have cumulatively been over-allocated production) is greater than our share of remaining reserves, we record a liability for the excess at period-end prices. We also do not recognize revenue for the production in tanks, oil marketed on behalf of joint interest owners in our properties, or oil that resides in pipelines prior to delivery to the purchaser. We did not have any net oil inventories in pipelines at December 31, 2007 or 2006. We did not have any natural gas imbalances at December 31, 2007 or 2006.

Commodity Derivative Contracts and Related Activities

We utilize various financial instruments for non-trading purposes to manage and reduce price volatility and other market risks associated with our oil and natural gas production. These arrangements are structured to reduce our exposure to commodity price decreases, but they can also limit the benefit we might otherwise receive from commodity price increases. Our risk management activity is generally accomplished through over-the-counter forward derivative or option contracts with large financial institutions.

We apply the provisions of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” and its amendments (“SFAS 133”). SFAS 133 requires each derivative instrument to be recorded in the balance sheet as either an asset or liability measured at fair value. We have elected to not designate our current portfolio of derivatives as hedges under SFAS 133. Therefore, the change in fair value of these instruments is recorded in current earnings and reflected in the Consolidated Statements of Operations as “Derivative fair value loss.”

See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” for discussion regarding our sensitivity analysis for financial instruments.

Unit-Based Compensation Expense

We account for unit-based compensation pursuant to SFAS 123R. SFAS 123R requires an entity to recognize the grant date fair value of stock options and other equity-based compensation issued to employees in the income statement. It establishes fair value as the measurement objective in accounting for share-based payment arrangements and requires companies to apply a fair value-based measurement method in accounting

71

ENCORE ENERGY PARTNERS LP

for share-based payment transactions with employees. For 2007, we recorded total compensation expense of approximately $6.8 million related to management incentive units and phantom units. Compensation expense related to equity awards is included in “General and administrative expense” in the Consolidated Statements of Operations.

New Accounting Pronouncements

SFAS No. 157, “Fair Value Measurements” (“SFAS 157”)

In September 2006, the 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. SFAS 157 is prospectively effective for financial assets and liabilities for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. 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 delays 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). We have elected a partial deferral of SFAS 157 for all instruments within the scope of FSP FAS 157-2, including but not limited to our asset retirement obligations. We will continue to evaluate the impact of SFAS 157 on these instruments during the deferral period. SFAS 157, as it relates to financial assets and liabilities, is effective beginning in the first quarter of 2008. SFAS 157 will have an impact on the calculation and reported fair value of our derivative contracts and related disclosures; however, we do not expect the change to have a material impact on our results of operations or financial condition.

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 is effective for fiscal years beginning after November 15, 2007. We adopted SFAS 159 effective January 1, 2008, and did not elect the fair value option for eligible instruments existing on that date. Therefore, the initial adoption of SFAS 159 did not have an impact on our results of operations or financial condition. We 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 our future results of operations or financial condition.

FSP on FASB Interpretation (“FIN”) 39-1, “Amendment of FASB Interpretation No. 39” (“FSP FIN 39-1”)

In April 2007, the FASB issued FSP FIN 39-1. FSP FIN 39-1 amends FIN No. 39, “Offsetting of Amounts Related to Certain Contracts” (“FIN 39”), to permit a reporting entity that is party to a master netting arrangement to offset the fair value amounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) against fair value amounts recognized for derivative instruments that have been offset under the same master netting arrangement in accordance with FIN 39. FSP FIN 39-1 is effective for fiscal years beginning after November 15, 2007. We adopted FSP FIN 39-1 effective January 1, 2008. The adoption of FSP FIN 39-1 did not have a material impact on our results of operations or financial condition.

72

ENCORE ENERGY PARTNERS LP

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 us). Early application is prohibited. We are evaluating the impact SFAS 141R will have on our results of operations and financial condition and the reporting of future acquisitions in our consolidated financial statements.

Information Concerning Forward-Looking Statements

This Report contains forward-looking statements, which give our current expectations or forecasts of future events. Forward-looking statements can be identified by the fact that they do not relate strictly to historical or current facts. These statements may include words such as “may,” “will,” “could,” “anticipate,” “estimate,” “expect,” “project,” “intend,” “plan,” “believe,” “should,” “predict,” “potential,” “pursue,” “target,” “continue,” and other words and terms of similar meaning. In particular, forward-looking statements included in this Report relate to, among other things, the following:

•  expected capital expenditures and the focus of our capital program;

•  areas of future growth;

•  our development program;

•  future secondary development and tertiary recovery potential;

•  anticipated prices for oil and natural gas and expectations regarding differentials between wellhead prices and benchmark prices (including, without limitation, the effects of increased Canadian oil production and refinery turnarounds);

•  projected results of operations;

•  timing and amount of future production of oil and natural gas;

•  availability of pipeline capacity;

•  expected commodity derivative positions and payments related to commodity derivative contracts;

•  expectations regarding working capital, cash flow, and anticipated liquidity;

•  projected borrowings under our revolving credit facility; and

•  the marketing of our oil and natural gas.

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” and elsewhere in this Report and in our other filings with the SEC. If one or more of these risks or uncertainties materialize (or the consequences of such a development changes), or should underlying assumptions prove incorrect, actual outcomes may vary materially from those forecasted or expected. We undertake no responsibility to update forward-looking statements for changes related to these or any other factors that may occur subsequent to this filing for any reason.

73

ENCORE ENERGY PARTNERS LP

ITEM 7A.   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.

Derivative policy.  Due to the historical volatility of crude oil and natural gas prices, we enter into various derivative instruments to manage our exposure to volatility in the market price of crude oil and natural gas. We use options (including floors and collars) and fixed price swaps to mitigate the impact of downward swings in prices on our cash available for distribution. All contracts are settled with cash and do not require the delivery of physical volumes to satisfy settlement. While this strategy may result in us having lower net cash inflows than we would otherwise have if we had not utilized these instruments in times of higher oil and natural gas prices, management believes that the resulting reduced volatility of cash flow is beneficial.

Counterparties.  At December 31, 2007, we had committed greater than 10 percent of either our outstanding oil or natural gas production represented by derivative contracts to the following counterparties:

	Percentage of			Percentage of
	Oil Derivative			Natural Gas
	Contracts			Derivative Contracts
Counterparty	Committed			Committed
Bank of America, N.A.		37.6	%		—
BNP Paribas		40.4	%		23.3	%
Calyon		5.7	%		17.8	%
Wachovia		2.5	%		58.9	%

We believe that the credit-worthiness of our counterparties is sound and do not anticipate any non-performance of contractual obligations. As long as each counterparty maintains an investment grade credit rating, no collateral is required.

In order to mitigate the credit risk of financial instruments, we enter into master netting agreements with significant counterparties. The master netting agreement is a standardized, bilateral contract between a given counterparty and us. Instead of treating separately each financial transaction between our counterparty and us, the master netting agreement enables our counterparty and us to aggregate all financial trades and treat them as a single agreement. This arrangement benefits us in three ways: (i) the netting of the value of all trades reduces the requirements of daily collateral posting by us, (ii) default by a counterparty under one financial trade can trigger rights for us to terminate all financial trades with such counterparty, and (iii) netting of settlement amounts reduces our credit exposure to a given counterparty in the event of close-out.

Commodity price sensitivity.  The tables in this section provide information about our commodity derivative contracts to which we were a party as of December 31, 2007.

We manage commodity price risk with swap contracts, put contracts, collars, and floor spreads. Swap contracts provide a fixed price for a notional amount of sales volumes. Put contracts provide a fixed floor price on a notional amount of sales volumes while allowing full price participation if the relevant index price closes above the floor price. Collars provide a floor price on a notional amount of sales volumes while allowing some additional price participation if the relevant index price closes above the floor price. Additionally, we may occasionally short sell put contracts with a strike price well below the floor price of a floor or collar in order to offset some of the cost of the contract. Combined, the short floor and long floor are called a floor spread. As of December 31, 2007, the fair market value of our oil commodity derivative contracts was a net liability of $0.3 million, and the fair value of our natural gas commodity derivative contracts was a net asset of $4.5 million. Based on our open commodity derivative positions at December 31,

74

ENCORE ENERGY PARTNERS LP

2007, a $1.00 increase in the respective NYMEX prices for oil and natural gas would decrease our net derivative fair value asset by approximately $5.6 million, while a $1.00 decrease in the respective NYMEX prices for oil and natural gas would increase our net derivative fair value asset by approximately $6.5 million.

The fair value of our derivative contracts are estimated based on quoted market prices from independent reporting services compared to the contract price of the agreement, and approximate the cash gain or loss that would have been realized if the contracts had been closed out at period end. All derivative positions offset physical positions exposed to the cash market. None of these offsetting physical positions are included in the tables below. Price risk sensitivities were calculated by assuming across-the-board increases in price of $1.00 per Bbl for oil and natural gas regardless of term of historical relationships between the contractual price of the instruments and the underlying commodity price.

Oil Derivative Contracts

																		Asset
	Daily		Average		Daily			Average		Daily		Average		Daily		Average		(Liability)
	Floor		Floor		Short Floor			Short Floor		Cap		Cap		Swap		Swap		Fair Market
Period	Volume		Price		Volume			Price		Volume		Price		Volume		Price		Value
	(Bbl)		(per Bbl)		(Bbl)			(per Bbl)		(Bbl)		(per Bbl)		(Bbl)		(per Bbl)		(in thousands)
Jan. 2008		2,500	$	65.00		(2,000	)	$	65.00		—	$	—		—	$	—	$	—
		2,000		75.00		—			—		—		—		—		—
Feb. — Dec. 2008		880		80.00		—			—		440		107.60		—		—		930
		2,000		75.00		—			—		—		—		—		—
		2,500		65.00		(2,000	)		65.00		—		—		—		—
2009		880		80.00		—			—		440		97.75		—		—		(3,050	)
		2,250		75.00		—			—		—		—		—		—
		1,250		63.40		(1,250	)		65.00		—		—		1,000		68.70
2010		880		80.00		—			—		440		93.80		—		—		52
		2,000		75.00		—			—		1,000		77.23		—		—
		2,000		65.00		(2,000	)		65.00		—		—		—		—
2011		1,000		80.00		—			—		1,000		94.65		—		—		1,811
		1,000		70.00		—			—		—		—		—		—
																		$	(257	)

Natural Gas Derivative Contracts

	Daily		Average		Daily		Average		Asset
	Floor		Floor		Cap		Cap		Market
Period	Volume		Price		Volume		Price		Value
	(Mcf)		(per Mcf)		(Mcf)		(per Mcf)		(in thousands)
Jan. 2008		2,000	$	8.20		2,000	$	9.85	$	119
		2,000		7.20		—		—
Feb. — Dec. 2008		3,800		8.20		3,800		9.83		1,798
		3,800		7.20		—		—
2009		3,800		8.20		3,800		9.83		1,376
		3,800		7.20		—		—
2010		3,800		8.20		3,800		9.58		1,240
		3,800		7.20		—		—
									$	4,533

75

ENCORE ENERGY PARTNERS LP

Interest rate sensitivity.  At December 31, 2007, we had total long-term debt of $47.5 million under our revolving credit facility, which 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 $0.5 million of interest expense per year, and if LIBOR decreased one percent, we would incur $0.5 million less.

Subsequent to December 31, 2007, as a result of the increase in debt levels resulting from the purchase of certain oil and natural gas producing properties and related assets in the Permian and Williston Basins, we entered into interest rate swaps 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.

76

ENCORE ENERGY PARTNERS LP

ITEM 8.   FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Index to Consolidated Financial Statements

	Page
Report of Independent Registered Public Accounting Firm		78
Consolidated Balance Sheets as of December 31, 2007 and 2006		79
Consolidated Statements of Operations for the Years Ended December 31, 2007, 2006, and 2005		80
Consolidated Statements of Partners’ Equity for the Years Ended December 31, 2007, 2006, and 2005		81
Consolidated Statements of Cash Flows for the Years Ended December 31, 2007, 2006, and 2005		82
Notes to Consolidated Financial Statements		83
Supplementary Information		106

77

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of Encore Energy Partners GP LLC
and Unitholders of Encore Energy Partners LP:

We have audited the accompanying consolidated balance sheets of Encore Energy Partners LP (the “Partnership”) as of December 31, 2007 and 2006, and the related consolidated statements of operations, partners’ equity, and cash flows for each of the three years in the period ended December 31, 2007. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Partnership’s internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of the Partnership at December 31, 2007 and 2006, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2007, in conformity with U.S. generally accepted accounting principles.

As discussed in Note 2 to the consolidated financial statements, on January 1, 2007, the Partnership adopted Financial Accounting Standards Board Interpretation No. 48, “Accounting for Uncertainty in Income Taxes — an Interpretation of FASB Statement No. 109.”

/s/ Ernst & Young LLP

Fort Worth, Texas

February 27, 2008

78

ENCORE ENERGY PARTNERS LP

CONSOLIDATED BALANCE SHEETS

	December 31,
	2007			2006
	(In thousands, except unit amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	3		$	—
Accounts receivable:
Trade		16,239			2,428
Affiliate		653			—
Derivatives		3,713			—
Prepaid expenses and other		448			—
Total current assets		21,056			2,428
Properties and equipment, at cost — successful efforts method:
Proved properties, including wells and related equipment		378,170			36,414
Accumulated depletion, depreciation, and amortization		(37,661	)		(11,919	)
		340,509			24,495
Other property and equipment		457			—
Accumulated depreciation		(50	)		—
		407			—
Intangibles, net		3,969			—
Derivatives		21,875			—
Debt issuance costs, net		1,451			—
Other		812			—
Total assets	$	390,079		$	26,923
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Accounts payable:
Trade	$	1,915		$	—
Affiliate		1,353			—
Accrued liabilities:
Lease operations expense		1,905			317
Development capital		2,249			—
Interest		147			—
Production, ad valorem, and severance taxes		5,448			463
Natural gas purchases		1,578			—
Derivatives		865			—
Other		2,452			15
Total current liabilities		17,912			795
Derivatives		20,447			—
Future abandonment cost		6,068			287
Deferred taxes		—			122
Long-term debt		47,500			—
Other		16			—
Total liabilities		91,943			1,204
Commitments and contingencies (see Note 4)		—			—
Partners’ equity:
Limited partners — 24,187,679 common units issued and outstanding at December 31, 2007		296,977			—
General partner		1,159			—
Owner’s net equity		—			25,719
Total partners’ equity		298,136			25,719
Total liabilities and partners’ equity	$	390,079		$	26,923

The accompanying notes are an integral part of these consolidated financial statements.

79

ENCORE ENERGY PARTNERS LP

CONSOLIDATED STATEMENTS OF OPERATIONS

	Year Ended December 31,
	2007			2006			2005
	(In thousands, except per unit amounts)
Revenues:
Oil	$	58,836		$	409		$	535
Natural gas		12,269			12,337			16,366
Marketing and other		8,582			—			—
Total revenues		79,687			12,746			16,901
Expenses:
Production:
Lease operations		13,920			1,673			1,751
Production, ad valorem, and severance taxes		8,571			1,226			1,473
Depletion, depreciation, and amortization		25,998			1,200			1,286
General and administrative		10,707			631			572
Marketing		6,673			—			—
Derivative fair value loss		26,301			—			—
Other operating		762			246			263
Total expenses		92,932			4,976			5,345
Operating income (loss)		(13,245	)		7,770			11,556
Other income (expenses):
Interest		(12,294	)		—			—
Other		196			—			—
Total other income (expenses)		(12,098	)		—			—
Income (loss) before income taxes		(25,343	)		7,770			11,556
Income tax (provision) benefit:
Current		(10	)		—			—
Deferred		12			(122	)		—
Net income (loss)	$	(25,341	)	$	7,648		$	11,556
Net loss allocation (see Note 8):
Limited partners’ interest in net loss	$	(18,617	)
General partner’s interest in net loss	$	(389	)
Net loss per common unit:
Basic	$	(0.78	)
Diluted	$	(0.78	)
Weighted average common units outstanding:
Basic		23,877
Diluted		23,877

The accompanying notes are an integral part of these consolidated financial statements.

80

ENCORE ENERGY PARTNERS LP

CONSOLIDATED STATEMENTS OF PARTNERS’ EQUITY

	Owner’s									Total
	Net			Limited			General			Partners’
	Equity			Partners			Partner			Equity
	(In thousands)
Balance at December 31, 2004	$	25,822		$	—		$	—		$	25,822
Net income		11,556			—			—			11,556
Net distributions to owner		(9,424	)		—			—			(9,424	)
Balance at December 31, 2005		27,954			—			—			27,954
Net income		7,648			—			—			7,648
Net distributions to owner		(9,883	)		—			—			(9,883	)
Balance at December 31, 2006		25,719			—			—			25,719
Contributions by EAC in connection with acquisition of Elk Basin assets		103,062			—			—			103,062
Distributions to owner		(4,231	)		—			—			(4,231	)
Net loss attributable to owner prior to IPO on September 17, 2007		(6,365	)		—			—			(6,365	)
Contribution of Permian Basin assets by EAC		(26,229	)		26,229			—			—
Allocation of owner’s net equity		(91,956	)		90,118			1,838			—
Issuance of common units to public in IPO		—			213,116			—			213,116
Underwriting and offering costs in conjunction with IPO		—			(19,253	)		(402	)		(19,655	)
Net loss attributable to unitholders subsequent to IPO		—			(18,587	)		(389	)		(18,976	)
Non-cash unit-based compensation		—			6,665			139			6,804
Distributions to unitholders		—			(1,311	)		(27	)		(1,338	)
Balance at December 31, 2007	$	—		$	296,977		$	1,159		$	298,136

The accompanying notes are an integral part of these consolidated financial statements.

81

ENCORE ENERGY PARTNERS LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended December 31,
	2007			2006			2005
	(In thousands)
Cash flows from operating activities:
Net income (loss)	$	(25,341	)	$	7,648		$	11,556
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation, and amortization		25,998			1,200			1,286
Non-cash unit-based compensation expense		6,804			—			—
Non-cash derivative fair value loss		27,543			—			—
Deferred taxes		(12	)		122			—
Other		527			16			10
Changes in operating assets and liabilities, net of effects from acquisition:
Accounts receivable		(13,020	)		1,991			(1,373	)
Current derivatives		(2,700	)		—			—
Other current assets		(447	)		—			—
Long-term derivatives		(19,717	)		—			—
Other assets		(812	)		—			—
Accounts payable		3,268			—			—
Other current liabilities		8,000			(58	)		125
Net cash provided by operating activities		10,091			10,919			11,604
Cash flows from investing activities:
Purchases of other property and equipment		(457	)		—			—
Acquisition of oil and natural gas properties		(330,294	)		—			—
Development of oil and natural gas properties		(6,645	)		(1,036	)		(2,180	)
Net cash used in investing activities		(337,396	)		(1,036	)		(2,180	)
Cash flows from financing activities:
Proceeds from issuance of common units, net of issuance costs		193,461			—			—
Proceeds from long-term debt, net of issuance costs		270,758			—			—
Payments on long-term debt		(225,000	)		—			—
Distributions to unitholders		(1,338	)		—			—
Contribution by EAC in connection with purchase of Elk Basin assets		93,658			—			—
Distributions to owner prior to IPO		(4,231	)		(9,883	)		(9,424	)
Net cash provided by (used in) financing activities		327,308			(9,883	)		(9,424	)
Increase in cash and cash equivalents		3			—			—
Cash and cash equivalents, beginning of period		—			—			—
Cash and cash equivalents, end of period	$	3		$	—		$	—

The accompanying notes are an integral part of these consolidated financial statements.

82

ENCORE ENERGY PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1.   Formation of the Partnership and Description of Business

Encore Energy Partners LP (“ENP” or the “Partnership”) was formed on February 13, 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 oil and natural gas properties and related assets in the Elk Basin of Wyoming and Montana (the “Elk Basin Assets”), which the Partnership acquired in March 2007 from certain subsidiaries of Anadarko Petroleum Corporation (“Anadarko”), 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 oil and natural gas properties and related assets in the Permian Basin of West Texas and Williston Basin of North Dakota, acquired from Encore Operating, L.P. (“Encore Operating”), a wholly owned subsidiary of EAC, in February 2008. See “Note 3. Acquisition” for additional discussion of the acquisition of the Elk Basin Assets. See “Note 12. Subsequent Events” for details regarding the Partnership’s February 2008 acquisition of the Permian and Williston Basin properties from Encore Operating. Prior to the closing of the IPO, EAC owned all the general and limited partner interests in the Partnership, with the exception of management incentive units owned by certain executive officers of the General Partner. See “Note 9. Unit-Based Compensation Plans” for additional discussion of the management incentive units.

Initial Public Offering and Concurrent Transactions

On September 17, 2007, the Partnership completed its IPO of 9,000,000 common units at a price to the public of $21.00 per unit. The net proceeds of $171.0 million, after deducting the underwriters’ discount and a structuring fee of $13.2 million, in the aggregate, and offering expenses of $4.7 million, were used to repay in full the $126.4 million of outstanding indebtedness under OLLC’s subordinated credit agreement and $43.5 million of outstanding borrowings under OLLC’s revolving credit facility. See “Note 6. Debt” for additional discussion of the Partnership’s long-term debt.

On October 11, 2007, the underwriters exercised their over-allotment option to purchase an additional 1,148,400 common units, which closed on October 16, 2007. The net proceeds of $22.4 million, after deducting the underwriters’ discount and a structuring fee of $1.7 million, were used to repay outstanding borrowings under OLLC’s revolving credit facility. After completion of the IPO and the underwriters’ over-allotment exercise, 42 percent of the Partnership’s common units were publicly held.

At the closing of the IPO on September 17, 2007, 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, 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.

83

ENCORE ENERGY PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 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. 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 receives an administrative fee of $1.75 per BOE of the Partnership’s production for such services and reimbursement of actual third-party expenses incurred 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.

The Partnership reimburses EAC for any additional state income, franchise, or similar tax paid by EAC resulting from the inclusion of the Partnership (and its subsidiaries) in a combined state income, franchise, or similar tax report with EAC as required by applicable law. The amount of any such reimbursement will be limited to the tax that the Partnership (and its subsidiaries) would have paid had it not been included in a combined group with EAC. See “Note 11. Related Party Transactions” for additional discussion regarding the Administrative Services Agreement.

(c) The Encore Energy Partners GP LLC Long-Term Incentive Plan (the “ENP Incentive Plan”) was approved, 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 9. Unit-Based Compensation Plans” for additional discussion regarding the ENP Incentive Plan.

Note 2.   Summary of Significant Accounting Policies

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 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. The Partnership and the Permian 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. The contribution of the Permian Basin Assets by EAC was accounted for as a transaction between entities under common control. Therefore, the assets and liabilities of the Permian Basin Assets were recorded on the Partnership’s balance sheet at EAC’s historical basis.

Use of Estimates

Preparing financial statements in conformity with accounting principles generally accepted in the United States requires management to make certain estimations and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities in the consolidated financial statements and the reported amounts of revenues and expenses reported. Actual results could differ materially from those estimates.

84

ENCORE ENERGY PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Estimates made in preparing these consolidated financial statements include, among other things, estimates of the proved oil and natural gas reserve volumes used in calculating depletion, depreciation, and amortization (“DD&A”) expense; the estimated future cash flows and fair value of properties used in determining the need for any impairment write-down; operating costs accrued; volumes and prices for revenues accrued; estimates of the fair value of equity-based compensation awards; and the timing and amount of future abandonment costs used in calculating asset retirement obligations. Future changes in the assumptions used could have a significant impact on reported results in future periods.

Cash and Cash Equivalents

Cash and cash equivalents include cash in banks, money market accounts, and all highly liquid investments with an original maturity of three months or less.

Prior to the formation of the Partnership, EAC provided cash as needed to support the operations of the Permian Basin Assets and collected cash from sales of production from the Permian Basin Assets. Consequently, the accompanying Consolidated Balance Sheet as of December 31, 2006 does not include any cash balances. Net cash paid to EAC prior to February 2007 is reflected as “Distributions to owner” on the accompanying Consolidated Statements of Partners’ Equity.

Supplemental Disclosures of Cash Flow Information

The following table sets forth supplemental disclosures of cash flow information for 2007 (in thousands):

Cash paid during the period for:
Interest	$	11,857
Non-cash investing and financing activities:
Contribution of derivative contracts from EAC		9,404
Contribution of Permian Basin Assets by EAC		26,229

The Partnership did not have supplemental disclosures of cash flow information for the years ended December 31, 2006 and 2005.

Accounts Receivable

The Partnership’s trade accounts receivable, which are primarily from oil and natural gas sales, are recorded at the invoiced amount and do not bear interest. The Partnership routinely reviews outstanding accounts receivable balances and assesses the financial strength of its customers. A reserve is recorded for amounts it expects will not be fully recovered. Actual balances are not applied against the reserve until substantially all collection efforts have been exhausted. At December 31, 2007 and 2006, the Partnership did not have any allowance for doubtful accounts.

Properties and Equipment

Oil and Natural Gas Properties.  The Partnership adheres to Statement of Financial Accounting Standards (“SFAS”) No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies” (“SFAS 19”), utilizing the successful efforts method of accounting for its oil and natural gas properties. Under this method, all costs associated with productive and nonproductive development wells are capitalized. Exploration expenses, including geological and geophysical expenses and delay rentals, are charged to expense as incurred. Costs associated with drilling exploratory wells are initially capitalized pending determination of whether the well is economically productive or nonproductive.

If an exploratory well does not find reserves or does not find reserves in a sufficient quantity as to make them economically producible, the previously capitalized costs are expensed in the Partnership’s Consolidated

85

ENCORE ENERGY PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Statements of Operations and shown as a non-cash adjustment to net income in the “Operating activities” section of the Partnership’s Consolidated Statements of Cash Flows in the period in which the determination was made. If an exploratory well finds reserves but they cannot be classified as proved, the Partnership continues to capitalize the associated cost as long as the well has found a sufficient quantity of reserves to justify its completion as a producing well and sufficient progress is being made in assessing the reserves and the operating viability of the project. If subsequently it is determined that neither of these conditions continues to exist, all previously capitalized costs associated with the exploratory well are expensed and shown as a non-cash adjustment to net income in the “Operating activities” section of the Partnership’s Consolidated Statements of Cash Flows in the period in which the determination was made. Re-drilling or directional drilling in a previously abandoned well is classified as development or exploratory based on whether it is in a proved or unproved reservoir. Expenditures for repairs and maintenance to sustain or increase production from the existing producing reservoir are charged to expense as incurred. Expenditures to recomplete a current well in a different unproved reservoir are capitalized pending determination that economic reserves have been added. If the recompletion is not successful, the expenditures are charged to expense. All capitalized costs associated with both development and exploratory wells are shown as “Development of oil and natural gas properties” in the “Investing activities” section of the Partnership’s Consolidated Statements of Cash Flows. The Partnership did not drill any exploratory wells during the three years ended December 31, 2007.

Significant tangible equipment added or replaced is capitalized. Expenditures to construct facilities or increase the productive capacity from existing reservoirs are capitalized. Capitalized costs are amortized on a unit-of-production basis over the remaining life of proved developed reserves or total proved reserves, as applicable. Natural gas volumes are converted to barrels of oil equivalent (“BOE”) at the rate of six thousand cubic feet (“Mcf”) of natural gas to one barrel (“Bbl”) of oil.

The costs of retired, sold, or abandoned properties that constitute part of an amortization base are charged or credited, net of proceeds received, to the accumulated DD&A reserve. Gains or losses from the disposal of other properties are recognized in the current period.

Miller and Lents, Ltd., independent reserve engineers, estimate the Partnership’s reserves annually on December 31. This results in a new DD&A rate which the Partnership uses for the preceding fourth quarter after adjusting for fourth quarter production. The Partnership internally estimates reserve additions and reclassifications of reserves from proved undeveloped to proved developed at the end of the first, second, and third quarters for use in determining a DD&A rate for the quarter.

In accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” (“SFAS 144”) the Partnership is required to assess the need for an impairment of capitalized costs of long-lived assets to be held and used, including proved oil and natural gas properties, whenever events and circumstances indicate that the carrying value of the asset may not be recoverable. If impairment is indicated based on a comparison of the asset’s carrying value to its undiscounted expected future net cash flows, then it is recognized to the extent that the carrying value exceeds fair value. Expected future net cash flows are based on existing proved reserve and production information and pricing assumptions that management believes are representative of future economics. Any impairment charge incurred is expensed and reduces the recorded basis in the asset.

Unproved properties, the majority of the costs of which relate to the acquisition of leasehold interests, are assessed for impairment on a property-by-property basis for individually significant balances and on an aggregate basis for individually insignificant balances. If the assessment indicates an impairment, a loss is recognized by providing a valuation allowance at the level consistent with the level at which impairment was assessed. The impairment assessment is affected by economic factors such as the results of exploration activities, commodity price outlooks, remaining lease terms, and potential shifts in business strategy employed by management. In the case of individually insignificant balances, the amount of the impairment loss recognized is determined by amortizing the portion of these properties’ costs which ENP believes will not be

86

ENCORE ENERGY PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

transferred to proved over the average life of the lease. The Partnership did not hold any unproved properties during the three years ended December 31, 2007.

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:

	December 31,
	2007		2006
	(In thousands)
Proved leasehold costs	$	297,777	$	18,261
Wells and related equipment — Completed		77,143		17,587
Wells and related equipment — In process		3,250		566
Total proved properties	$	378,170	$	36,414

Other Property and Equipment.  Other property and equipment is carried at cost. Depreciation is expensed on a straight-line basis over estimated useful lives, which range from three to seven years.

Intangible Assets

The Partnership accounts for intangible assets under the provisions of SFAS No. 142, “Goodwill and Other Intangible Assets” (“SFAS 142”). Intangible assets with definite useful lives are amortized over their estimated useful lives. In accordance with SFAS 144, the Partnership evaluates the recoverability of intangible assets with definite useful lives whenever events or changes in circumstances indicate that the carrying value of the asset may not be fully recoverable. An impairment loss exists when estimated undiscounted cash flows expected to result from the use of the asset and its eventual disposition are less than its carrying amount.

In connection with the Partnership’s acquisition of the Elk Basin Assets, the Partnership acquired a contract to purchase natural gas at a below market price for use as field fuel. The fair value of this contract, net of related amortization, is shown as “Intangibles, net” on the accompanying Consolidated Balance Sheet as of December 31, 2007. The value of this contract is amortized on a straight-line basis over its estimated useful life of approximately 14 years. As of December 31, 2007, the gross carrying amount of the contract was $4.2 million, and accumulated amortization was $0.3 million. For 2007, the Partnership recorded $0.3 million amortization expense related to this contract. For each of the next five years, the Partnership expects amortization expense to be approximately $0.3 million per year.

Asset Retirement Obligations

SFAS No. 143, “Accounting for Asset Retirement Obligations” requires that the fair value of a liability for an asset retirement obligation (“ARO”) be recognized in the period in which the liability is incurred. For oil and natural gas properties, this is the period in which an oil or natural gas well is acquired or drilled. An amount equal to and offsetting the ARO is capitalized as part of the carrying amount of the Partnership’s oil and natural gas properties at its discounted fair value. The liability is then accreted each period until it is settled or the well is sold, at which time the liability is reversed. Estimates are based on historical experience in plugging and abandoning wells and estimated remaining field life based on reserve estimates. The Partnership does not provide for a market risk premium associated with AROs because a reliable estimate cannot be determined. See “Note 5. Asset Retirement Obligations” for additional information.

Environmental Costs

The Partnership capitalizes or expenses environmental expenditures, as appropriate, depending on whether the expenditure has a future economic benefit. Expenditures that relate to an existing condition caused by past

87

ENCORE ENERGY PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

operations and that have no future economic benefit are expensed. Liabilities for such expenditures are recorded on an undiscounted basis when environmental assessments or clean-ups are probable and the costs can be reliably estimated. Expenditures that extend the life of the related property or mitigate or prevent future environmental contamination are capitalized.

Unit-Based Compensation

The Partnership does not have any employees. However, the ENP Incentive Plan provides for the grant of unit awards and unit-based awards for employees, consultants, and directors of EAC, the General Partner, and any of their affiliates that perform services for the Partnership. In addition, in May 2007, the board of directors of the General Partner issued 550,000 management incentive units to certain executive officers of the General Partner.

The Partnership accounts for unit-based compensation according to the provisions of SFAS No. 123 (revised 2004), “Share-Based Payment” (“SFAS 123R”). SFAS 123R requires the recognition of compensation expense, over the requisite service period, in an amount equal to the fair value of unit-based payments granted. See “Note 9. Unit-Based Compensation Plans” for additional discussion of the Partnership’s unit-based compensation plans.

For 2006 and 2005, a portion of the general and administrative (“G&A”) expenses and lease operating expenses allocated to the Partnership to reflect the carve out operations of the Predecessor was non-cash stock-based compensation recorded on the books of EAC. On January 1, 2006, EAC adopted the provisions of SFAS 123R using the “modified prospective” method. SFAS 123R revised SFAS No. 123, “Accounting for Stock-Based Compensation” and superseded Accounting Principles Board (“APB”) Opinion No. 25, “Accounting for Stock Issued to Employees” (“APB 25”). Prior to the adoption of SFAS 123R, employee stock options and restricted stock awards were accounted for according to the provisions of APB 25, which resulted in no compensation expense being recorded by EAC for stock options, as all options that were granted to EAC employees or non-employee directors had an exercise price equal to or greater than the common stock price on the date of grant. However, expense was recorded by EAC and allocated to the Predecessor related to restricted stock granted to EAC employees. Allocated compensation expense associated with awards to employees who are eligible for retirement was recognized over the explicit service period of the award under APB 25. If EAC had recognized compensation expense at the time an employee became eligible for retirement and had satisfied all service requirements, non-cash stock-based compensation expense allocable to the Predecessor would have increased by $33,000 in 2005.

During 2005, if compensation expense for the stock-based awards had been determined using the provisions of SFAS 123R, the Partnership’s net income would have been as follows on a pro forma basis (in thousands):

As Reported:
Non-cash stock-based compensation	$	120
Net income		11,556
Pro Forma:
Non-cash stock-based compensation		167
Net income		11,509

Segment Reporting

The Partnership has only one operating segment during the years presented — the development and exploitation of oil and natural gas reserves in the United States. A single management team administers all properties as a whole rather than by discrete operating segments. The Partnership does not track all material costs to develop and operate its properties at a level lower than the total Partnership level, nor does its current

88

ENCORE ENERGY PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

internal reporting structure allow for accurate tracking at a lower level. Throughout the year, the Partnership allocates capital resources to projects on a project-by-project basis, across its entire asset base to maximize profitability without regard to individual areas.

Major Customers/Concentration of Credit Risk

For 2007, the Partnership’s largest purchasers included Marathon Oil Corporation and ConocoPhillips, which accounted for 52 percent and 16 percent of the Partnership’s total sales of production, respectively. For 2006 and 2005, Chevron Corporation accounted for 24 percent and 19 percent of total sales of production, respectively.

Income Taxes

ENP is treated as a partnership for federal and state income tax purposes with each partner being separately taxed on his share of the Partnership’s taxable income. Therefore, no provision for current or deferred federal income taxes has been provided for in the accompanying consolidated financial statements. However, in May 2006, the state of Texas enacted a new business tax (the “Texas Margin Tax”) that replaced the Texas franchise tax. The Texas Margin Tax is applicable to numerous types of entities that previously were not subject to the franchise tax. ENP’s provision for income taxes is applicable to these state tax obligations under the Texas Margin Tax. In 2006, a deferred tax liability and related income tax expense was recognized for the expected future tax effect of the Texas Margin Tax due to the difference between the book and tax bases of the Permian Basin Assets. ENP has not paid any cash taxes for 2007, 2006, or 2005.

Net income for financial statement purposes may differ significantly from taxable income reportable to unitholders as a result of differences between the tax bases and financial reporting bases of assets and liabilities and the taxable income allocation requirements under the partnership agreement. In addition, individual unitholders have different investment bases depending upon the timing and price of acquisition of their common units, and each unitholder’s tax accounting, which is partially dependent upon the unitholder’s tax position, differs from the accounting followed in the consolidated financial statements. As a result, the aggregate difference in the basis of net assets for financial and tax reporting purposes cannot be readily determined as the Partnership does not have access to information about each unitholder’s tax attributes in the Partnership.

On January 1, 2007, ENP adopted the provisions of Financial Accounting Standards Board (“FASB”) Interpretation No. 48, “Accounting for Uncertainty in Income Taxes — an Interpretation of FASB Statement No. 109” (“FIN 48”). FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an entity’s financial statements in accordance with SFAS No. 109, “Accounting for Income Taxes.” FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The adoption of FIN 48 did not have a material impact on ENP’s financial condition, results of operations, or cash flows. Any interest assessed by the taxing authorities would be included in “Interest expense” and penalties related to income taxes would be included in “Other expense” on the accompanying Consolidated Statements of Operations. ENP has not recognized any interest or penalties for 2007.

Revenue Recognition

Revenues are recognized for the Partnership’s share of jointly owned properties as oil and natural gas is produced and sold, net of royalties. Natural gas revenues are also reduced by any processing and other fees paid, except for transportation costs paid to third parties, which are recorded as expense in “Other operating” in the accompanying Consolidated Statements of Operations. Natural gas revenues are recorded using the sales method of accounting, whereby revenue is recognized based on actual sales of natural gas rather than as the proportionate share of natural gas production. Royalties and severance taxes are paid based upon the actual

89

ENCORE ENERGY PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

price received from the sales. To the extent actual quantities and values of oil and natural gas are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volumes and values for those properties are estimated and recorded as accounts receivable in the accompanying Consolidated Balance Sheets. The Partnership does not have natural gas imbalances as ENP does not market its own natural gas production from wells of which it is not the operator. Encore Operating markets all the natural gas production from the wells that it operates and remits the non-operating interest owners’ share upon collection. As a result, ENP does not have any producer gas imbalances at the end of any of the years presented. The Partnership does not recognize revenue for the production in tanks, oil marketed on behalf of joint owners in the Partnership’s oil and natural gas properties, or oil in pipelines that has not been delivered to the purchaser. As of December 31, 2007 and 2006, the Partnership did not have any oil inventory in pipelines.

Marketing Revenues and Expenses

In March 2007, the Partnership acquired a crude oil pipeline and a natural gas pipeline from Anadarko 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, pipeline tariffs are collected for transportation through the crude oil pipeline.

Marketing revenues includes the sales of natural gas purchased from third parties as well as pipeline tariffs charged for transportation volumes through the Partnership’s crude oil pipeline. Revenues derived from sales of natural gas purchased from third parties are recognized when persuasive evidence of a sales arrangement exists, delivery has occurred, the sales price is fixed or determinable, and collectibility is reasonably assured. Marketing expenses includes the cost of natural gas volumes purchased from third parties. As ENP takes title to the natural gas and has risks and rewards of ownership, these transactions are presented gross in the Consolidated Statements of Operations, unless they meet the criteria for netting as outlined in EITF Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty” (“EITF 04-13”). The Partnership did not have any marketing activities prior to 2007.

Shipping Costs

Shipping costs of the Partnership’s production in the form of pipeline fees and trucking costs paid to third parties are incurred to transport oil and natural gas production from certain properties to a different market location for ultimate sale. These costs are included in “Other operating expense” and “Marketing expense,” as applicable, in the Partnership’s Consolidated Statements of Operations.

Derivatives

ENP uses various financial instruments for non-trading purposes to manage and reduce price volatility and other market risks associated with the Partnership’s oil and natural gas production. These arrangements are structured to reduce the Partnership’s exposure to commodity price decreases, but they can also limit the benefit the Partnership might otherwise receive from commodity price increases. ENP’s risk management activity is generally accomplished through over-the-counter forward derivative or option contracts with large financial institutions.

The Partnership applies the provisions of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” and its amendments (“SFAS 133”). SFAS 133 requires each derivative instrument to be recorded in the balance sheet as either an asset or liability measured at fair value. The Partnership has elected to not designate its current portfolio of derivatives as hedges and records mark-to-market gains or losses each quarter to “Derivative fair value loss” in the accompanying Consolidated Statements of Operations.

90

ENCORE ENERGY PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Allocation of Net Income (Loss)

The Partnership’s net income (loss) is allocated to partner equity accounts in accordance with the provisions of the partnership agreement.

For purposes of calculating earnings per unit, the Partnership allocates net income (loss) to its limited partners and participating securities, including general partner units, each quarter under the provisions of Emerging Issues Task Force Issue No. 03-6, “Participating Securities and the Two-Class Method under FASB Statement No. 128” (“EITF 03-6”).

Earnings Per Unit

The Partnership calculates net income (loss) per common unit in accordance with SFAS No. 128, “Earnings per Share” (“SFAS 128”). Under the two-class method of calculating earnings per unit 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 earnings per unit, the general partner units and management incentive units are participating securities. Net income (loss) per common unit is calculated by dividing the limited partners’ interest in net income (loss), after deducting the interests of the participating securities, by the weighted average number of common units outstanding. See “Note 8. Earnings Per Common Unit” for additional discussion.

For periods prior to the IPO, the Partnership was wholly owned by EAC, other than management incentive units owned by certain executive officers of the General Partner. Accordingly, earnings per unit is not presented for those periods.

New Accounting Pronouncements

SFAS No. 157, “Fair Value Measurements” (“SFAS 157”)

In September 2006, the 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. SFAS 157 is prospectively effective for financial assets and liabilities for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. 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 delays 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 has 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. The Partnership will continue to evaluate the impact of SFAS 157 on these instruments during the deferral period. SFAS 157, as it relates to financial assets and liabilities, is effective beginning in the first quarter of 2008. SFAS 157 will have an impact on the calculation and reported fair value of the Partnership’s derivative contracts and related disclosures; however, the Partnership does not expect the change to have a material impact on its results of operations or financial condition.

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

91

ENCORE ENERGY PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

resulting changes in fair value reported in earnings. SFAS 159 is effective for fiscal years beginning after November 15, 2007. The Partnership adopted SFAS 159 effective January 1, 2008, and did not elect the fair value option for eligible instruments existing on that date. Therefore, the initial adoption of 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.

FSP on FASB Interpretation (“FIN”) 39-1, “Amendment of FASB Interpretation No. 39” (“FSP FIN 39-1”)

In April 2007, the FASB issued FSP FIN 39-1. FSP FIN 39-1 amends FIN No. 39, “Offsetting of Amounts Related to Certain Contracts” (“FIN 39”), to permit a reporting entity that is party to a master netting arrangement to offset the fair value amounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) against fair value amounts recognized for derivative instruments that have been offset under the same master netting arrangement in accordance with FIN 39. FSP FIN 39-1 is effective for fiscal years beginning after November 15, 2007. The Partnership adopted FSP FIN 39-1 effective January 1, 2008. The adoption of FSP FIN 39-1 did not have a material impact on its 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.

Note 3.   Acquisition

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 the sellers approximately $328.4 million for the Elk Basin Assets. In August 2007, ENP paid an additional $0.8 million for the Elk Basin Assets as a result of customary post-closing adjustments. In October 2007, certain fixed assets were purchased from Anadarko in connection with the acquisition, resulting in an additional $0.4 million purchase price.

92

ENCORE ENERGY PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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. Natural gas liquids are produced as a byproduct of the flue gas tertiary recovery project and are sold at market prices. The revenues generated by these hydrocarbon liquids 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.

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 6. Debt” for additional discussion of the Partnership’s long-term debt.

The following unaudited pro forma condensed financial data 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, 2005. 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 the dates indicated and are not intended to be a projection of future results.

	Year Ended December 31,
	2007			2006			2005
	(In thousands, except per unit amounts)
Pro forma total revenues	$	93,848		$	82,485		$	75,066
Pro forma net loss	$	(27,801	)	$	(6,604	)	$	(10,900	)
Pro forma net loss per common unit:
Basic	$	(0.78	)
Diluted	$	(0.78	)

93

ENCORE ENERGY PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

For the 2006 and 2005, the Partnership was wholly owned by EAC. Accordingly, earnings per unit has not been calculated for those periods.

Note 4.   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 on 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 below. See the contractual obligations table included in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Report for contractual obligations as of December 31, 2007.

Note 5.   Asset Retirement Obligations

The Partnership’s primary AROs 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 future abandonment liability, the long-term portion of which is recorded in “Future abandonment cost” on the accompanying Consolidated Balance Sheets, for the periods indicated:

	Year Ended
	December 31,
	2007			2006
	(In thousands)
Future abandonment liability at January 1	$	296		$	276
Wells drilled		28			4
Accretion of discount		309			14
Plugging and abandonment costs incurred		(103	)		—
Revision of estimates		83			2
Liability assumed in Elk Basin acquisition		5,798			—
Future abandonment liability at December 31	$	6,411		$	296

Approximately $4.4 million of the future abandonment liability as of December 31, 2007 represents the cost for decommissioning the Elk Basin natural gas processing plant. The Partnership expects to continue reserving additional amounts based on the estimated timing to cease operations of the natural gas processing plant. In addition to the future abandonment liability for the Elk Basin plant, as of December 31, 2007, the Partnership has recorded an estimated liability of $1.0 million related to required environmental plant compliance costs caused by past operations of the plant. The liability was assumed from Anadarko in the acquisition of the Elk Basin Assets, and is reflected as a component of “Other current liabilities” on the Consolidated Balance Sheet as of December 31, 2007. The liability was estimated based on directives from the Bureau of Land Management for required cleanup of environmental contamination.

Note 6.   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

94

ENCORE ENERGY PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

be made to OLLC from time to time and letters of credit to be issued from time to time for the account of OLLC or any of its restricted subsidiaries.

The aggregate amount of the commitments of the lenders under the OLLC Credit Agreement is $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 December 31, 2007, the borrowing base was $145 million.

The OLLC Credit Agreement matures on March 7, 2012. 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.

Loans under the OLLC 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 the Partnership) is the rate per year equal to the London Interbank Offered Rate (“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.

As of December 31, 2007, the aggregate principal amount of loans outstanding under the OLLC Credit Agreement was $47.5 million and there were $0.1 million of outstanding letters of credit. Outstanding letters of credit reduce the availability under the OLLC Credit Agreement. Borrowings under the OLLC Credit Agreement may be repaid from time to time without penalty.

On August 22, 2007, OLLC entered into an amendment to the OLLC Credit Agreement to modify certain financial covenants. The amendment did not impact any other provisions in the OLLC Credit Agreement. The covenants, as amended, 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 the assets of the Partnership, OLLC and its restricted subsidiaries, subject to permitted exceptions;

•  restrictions on merging and selling assets outside the ordinary course of business;

•  restrictions on use of proceeds, investments, transactions with affiliates, or change of principal business;

95

ENCORE ENERGY PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

•  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 OLLC 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 OLLC 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 OLLC Credit Agreement) of not more than 3.5 to 1.0.

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 December 31, 2007, OLLC was in compliance with all debt covenants under the OLLC Credit Agreement, as amended.

OLLC incurs a commitment fee on the unused portion of the OLLC Credit Agreement determined based on the ratio of amounts outstanding under the OLLC Credit Agreement to the borrowing base in effect on such date. The following table summarizes the calculation of the commitment fee under the OLLC 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	%

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, including accrued interest, was repaid using a portion of the net proceeds from the IPO.

Long-Term Debt Maturities

The following table illustrates the Partnership’s long-term debt maturities at December 31, 2007:

	Payments Due by Period
	Total		2008		2009		2010		2011		2012		Thereafter
	(In thousands)
Revolving credit facility	$	47,500	$	—	$	—	$	—	$	—	$	47,500	$	—

For 2007, cash payments for interest totaled $11.9 million. The Partnership did not have any interest payments for 2006 or 2005.

96

ENCORE ENERGY PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

During 2007, the weighted average interest rate for total indebtedness was 8.5 percent.

Note 7.   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 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 9. Unit-Based Compensation Plans” for additional discussion of the management incentive units.

On November 14, 2007, the Partnership paid a prorated quarterly distribution of $0.053 per unit for the period from and including September 17, 2007 (the closing date of the IPO) through September 30, 2007. The total distribution of $1.3 million was paid to unitholders of record as of the close of business on November 8, 2007.

Note 8.   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 2007, EPU is calculated based on the net loss for the period from the closing of the IPO on September 17, 2007 through December 31, 2007.

For 2007, EPU is calculated by dividing the limited partners’ interest in net loss, after deducting the interests of participating securities, and deducting the net loss prior to IPO, by the weighted average number of common units outstanding. For periods prior to the IPO, 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 those periods.

97

ENCORE ENERGY PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following table presents the allocation of net loss to the limited partners for the period subsequent to the IPO and reflects EPU computations for 2007 (in thousands, except per unit data):

Net loss	$	(25,341	)
Less: Net loss prior to IPO		(6,365	)
Net loss attributable to unitholders subsequent to IPO	$	(18,976	)
Numerator:
Net loss attributable to unitholders subsequent to IPO	$	(18,976	)
Less: Net loss allocation to participating securities(a)		(359	)
Net loss available to limited partners	$	(18,617	)
Denominator:
Denominator for basic EPU:
Weighted average common units outstanding		23,877
Effect of dilutive management incentive units(b)		—
Denominator for diluted EPU		23,877
Net loss per common unit:
Basic	$	(0.78	)
Diluted	$	(0.78	)

(a)  The net loss allocation to participating securities includes the General Partner’s interest in the net loss of the Partnership, offset by the quarterly distribution to the General Partner and holders of management incentive units for the third quarter 2007.

(b)  A total of 550,000 management incentive units, which represent 687,500 common unit equivalents, were outstanding at December 31, 2007 but not included in the above calculation of diluted EPU for 2007 because their effect would be antidilutive. See additional discussion of management incentive units in “Note 9. Unit-Based Compensation Plans.”

As discussed in “Note 12.  Subsequent Events,” on February 7, 2008, the Partnership completed the acquisition of certain oil and natural gas producing properties and related assets in the Permian and Williston Basins from Encore Operating. As partial consideration for the transaction, the Partnership issued 6,884,776 common units representing limited partner interests to Encore Operating. As of February 20, 2008, there were 31,072,455 outstanding common units.

Note 9.   Unit-Based Compensation Plans

Management Incentive Units

In May 2007, the board of directors of the General Partner issued 550,000 management incentive units to certain executive officers of the General Partner. 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

98

ENCORE ENERGY PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

•  the holder’s death or disability.

For purposes of the management incentive units, a change in control of the General Partner is defined as the occurrence of one or more of the following events:

•  a “Change in Control” as defined in EAC’s 2000 Incentive Stock Plan;

•  any person or group, other than EAC and its affiliates, becomes the beneficial owner, by way of merger, consolidation, recapitalization, reorganization, or otherwise, of 50 percent or more of the combined voting power of the equity interests in the General Partner;

•  the limited partners approve, in one or a series of transactions, a plan of complete liquidation of the Partnership;

•  the sale or disposition by either the General Partner or the Partnership of all or substantially all of its assets in one or more transactions to any person other than the General Partner or an affiliate of the General Partner; or

•  a transaction resulting in a person other than the General Partner or one of its affiliates being the general partner of the Partnership.

A management incentive unit was initially convertible into one common unit. The conversion rate per management incentive unit is equal to the annualized distribution rate per management incentive unit immediately prior to conversion divided by the annualized distribution rate per common unit, with a maximum conversion rate of 4.7684 common units per management incentive unit. The following table sets forth the annualized distribution rate per management incentive unit after 10 percent compounding increases in the Partnership’s distribution rate to unitholders and the aggregate number of common units into which the management incentive units are convertible:

Annualized Management Incentive Units

Conversion and Distribution Summary

Common Units					Management Incentive Units
Annualized					Annualized				Common
Distribution		Percentage			Distribution		Conversion		Unit
per Unit		Increase			per Unit		Rate per Unit		Equivalents
$	1.40		—		$	1.40		1.0000		550,000
$	1.54		10.0	%	$	1.93		1.2500		687,500
$	1.69		10.0	%	$	2.65		1.5625		859,375
$	1.86		10.0	%	$	3.64		1.9531		1,074,205
$	2.05		10.0	%	$	5.00		2.4414		1,342,770
$	2.25		10.0	%	$	6.88		3.0518		1,678,490
$	2.48		10.0	%	$	9.46		3.8147		2,098,085
$	2.73		10.0	%	$	13.01		4.7684		2,622,620

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

99

ENCORE ENERGY PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

•  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.

The holders of management incentive units do not have any voting rights with respect to the units.

The fair value of the management incentive units granted in 2007 was estimated on the date of grant using a discounted dividend model. The management incentive units vest in three equal installments. The first installment vested upon the closing of the IPO, and the subsequent vesting will occur on the first and second anniversary of such closing date. For 2007, the Partnership recognized total compensation expense of $6.8 million for the management incentive units, which is included in “General and administrative expense” in the accompanying Consolidated Statements of Operations. As of December 31, 2007, ENP had $4.8 million of total unrecognized compensation cost related to unvested, outstanding management incentive units, which is expected to be recognized over a weighted average period of 0.7 years. For the first quarter of 2008 through the third quarter 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 since the initial issuance.

ENP Incentive Plan

As discussed in “Note 1. Formation of the Partnership and 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. As of December 31, 2007, there were 1,130,000 units available for issuance 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. 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 123R. 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 a portion of the liability as a component of other current liabilities and a portion of the liability as other noncurrent liabilities on the Consolidated Balance Sheet. As of December 31, 2007, the total liability was $31,000. 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.

For 2007, the Partnership recognized total compensation expense of approximately $31,000 for the phantom units, which is included in “General and administrative expense” in the accompanying Consolidated Statements of Operations. Subsequent to December 31, 2007, the board of directors of the General Partner issued 5,000 phantom units to a new board member pursuant to the ENP Incentive Plan. There have not been any forfeitures of phantom units.

100

ENCORE ENERGY PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 10.   Financial Instruments

The carrying value of the Partnership’s cash, 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. Commodity derivative contracts are marked-to-market each quarter in accordance with the provisions of SFAS 133.

Derivative Financial Instruments

The Partnership manages commodity price risk with swap contracts, put contracts, collars, and floor spreads. Swap contracts provide a fixed price for a notional amount of volume. Put contracts provide a fixed floor price on a notional amount of volume while allowing full price participation if the relevant index price closes above the floor price. Collar contracts provide a floor price for a notional amount of volume while allowing some additional price participation if the relevant index price closes above the floor price. Additionally, the Partnership occasionally sells put contracts with a strike price well below the floor price of an existing or new floor. Combined, the short floor and long floor are called a floor spread.

In connection with the acquisition of the Elk Basin Assets, EAC purchased floor contracts for 2,500 Bbls per day (“Bbls/D”) of production at $65.00 per Bbl for April 2007 through December 2008 that were all later contributed to the Partnership at their fair market value on the date of transfer of $9.4 million. In addition to these contributed derivatives, the Partnership has purchased additional derivative financial instruments as part of its risk management strategy.

The following tables summarize the Partnership’s open commodity derivative instruments as of December 31, 2007:

Oil Derivative Contracts

																		Asset
	Daily		Average		Daily			Average		Daily		Average		Daily		Average		(Liability)
	Floor		Floor		Short Floor			Short Floor		Cap		Cap		Swap		Swap		Fair Market
	Volume		Price		Volume			Price		Volume		Price		Volume		Price		Value
	(Bbl)		(per Bbl)		(Bbl)			(per Bbl)		(Bbl)		(per Bbl)		(Bbl)		(per Bbl)		(in thousands)
Jan. 2008		2,500	$	65.00		(2,000	)	$	65.00		—	$	—		—	$	—	$	—
		2,000		75.00		—			—		—		—		—		—
Feb. — Dec. 2008		880		80.00		—			—		440		107.60		—		—		930
		2,000		75.00		—			—		—		—		—		—
		2,500		65.00		(2,000	)		65.00		—		—		—		—
2009		880		80.00		—			—		440		97.75		—		—		(3,050	)
		2,250		75.00		—			—		—		—		—		—
		1,250		63.40		(1,250	)		65.00		—		—		1,000		68.70
2010		880		80.00		—			—		440		93.80		—		—		52
		2,000		75.00		—			—		1,000		77.23		—		—
		2,000		65.00		(2,000	)		65.00		—		—		—		—
2011		1,000		80.00		—			—		1,000		94.65		—		—		1,811
		1,000		70.00		—			—		—		—		—		—
																		$	(257	)

101

ENCORE ENERGY PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Natural Gas Derivative Contracts

	Daily		Average		Daily		Average		Asset Fair
	Floor		Floor		Cap		Cap		Market
Period	Volume		Price		Volume		Price		Value
	(Mcf)		(per Mcf)		(Mcf)		(per Mcf)		(in thousands)
Jan. 2008		2,000	$	8.20		2,000	$	9.85	$	119
		2,000		7.20		—		—
Feb. — Dec. 2008		3,800		8.20		3,800		9.83		1,798
		3,800		7.20		—		—
2009		3,800		8.20		3,800		9.83		1,376
		3,800		7.20		—		—
2010		3,800		8.20		3,800		9.58		1,240
		3,800		7.20		—		—
									$	4,533

Commodity Contracts — Mark-to-Market Accounting: Floor Spreads.  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. During 2007, the Partnership entered into floor spreads with a $75 per Bbl purchased floor and a $65 per Bbl short floor for 2,000 Bbls/D in 2008 and 2010 and 1,250 Bbls/D in 2009. As with the Partnership’s other derivative contracts, these are marked-to-market each quarter through “Derivative fair value loss” in the accompanying Consolidated Statements of Operations. In the above table, the purchased floor component and the short floor component of these floor spreads has been included with the Partnership’s other floor contracts and the short floor component is shown separately as negative volumes. The net cash flows per Bbl upon settlement of the contracts and payment of the related premiums when viewed together change depending on the NYMEX oil price as follows:

•  When the NYMEX oil price is greater than $75 per Bbl, the Partnership pays the net purchased floor premium cost per Bbl.

•  When the NYMEX oil price is greater than $65 per Bbl but less than $75 per Bbl, the Partnership receives settlements of $75 per Bbl less the NYMEX oil price and pays the net purchased floor premium cost per Bbl.

•  When the NYMEX oil price is below $65 per Bbl, the Partnership receives $10 per Bbl less the net purchased floor premium cost per Bbl.

Commodity Contracts — Current Period Impact.  As a result of derivative transactions for oil and natural gas, the Partnership recognized derivative fair value losses related to changes in the market value of commodity derivatives and settlements on derivative contracts for 2007. The Predecessor did not have any commodity derivative contracts; therefore, no derivative fair value gains or losses are reported for 2006 and 2005. The following table summarizes the components of derivative fair value loss for 2007 (in thousands):

Mark-to-market loss on commodity contracts	$	23,470
Premium amortization		4,073
Settlements on commodity contracts		(1,242	)
Total derivative fair value loss	$	26,301

102

ENCORE ENERGY PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Counterparty Risk.  At December 31, 2007, the Partnership had committed greater than 10 percent of either its oil or natural gas production represented by derivative contracts to the following counterparties:

				Percentage of
	Percentage of			Natural
	Oil Derivative			Gas Derivative
	Contracts			Contracts
Counterparty	Committed			Committed
Bank of America, N.A.		37.6	%		—
BNP Paribas		40.4	%		23.3	%
Calyon		5.7	%		17.8	%
Wachovia		2.5	%		58.9	%

The Partnership believes the credit-worthiness of its counterparties is sound and does not anticipate any non-performance of contractual obligations. As long as each counterparty maintains an investment grade credit rating, pursuant to ENP’s derivative contracts, no collateral is required.

In order to mitigate the credit risk of financial instruments, ENP enters into master netting agreements with significant counterparties. The master netting agreement is a standardized, bilateral contract between a given counterparty and ENP. Instead of treating separately each financial transaction between the counterparty and ENP, the master netting agreement enables the counterparty and ENP to aggregate all financial trades and treat them as a single agreement. This arrangement benefits ENP in three ways: (i) the netting of the value of all trades reduces the requirements of daily collateral posting by ENP, (ii) default by a counterparty under one financial trade can trigger rights to terminate all financial trades with such counterparty, and (iii) netting of settlement amounts reduces ENP’s credit exposure to a given counterparty in the event of close-out.

Note 11.   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. Formation of the Partnership and 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. Under the Administrative Services Agreement, Encore Operating receives an administrative fee of $1.75 per BOE of the Partnership’s production for such services and reimbursement for actual third-party expenses incurred on the Partnership’s behalf. The Partnership also pays its share of expenses that are directly chargeable to wells under joint operating 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. 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. In 2007, the Partnership paid $2.8 million to Encore Operating for administrative fees under the Administrative Services Agreement (including payment of any COPAS recovery) and $3.5 million for reimbursement of actual third-party expenses incurred on the Partnership’s behalf. Expenses incurred under the Administrative Services Agreement and third-party expenses billed by EAC to the Partnership are included in “General and administrative expenses” in the accompanying Consolidated Statements of Operations. As of December 31, 2007, the Partnership had a payable to EAC of $1.4 million for services provided by Encore Operating, which is reflected in “Accounts payable — affiliate” in the accompanying Consolidated Balance Sheet. As of December 31, 2007, the Partnership had a receivable from EAC of $0.7 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. The Partnership did not have a related party receivable or payable balance as of December 31, 2006.

On November 14, 2007, the third quarter distribution was paid to unitholders at a rate of $0.053 per unit, which was based on an initial quarterly distribution of $0.35 per unit, prorated from the period from and

103

ENCORE ENERGY PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

including September 17, 2007 (the closing date of the IPO) through September 30, 2007. The Partnership distributed approximately $0.7 million to EAC as holders of 14,039,279 common units and approximately $27,000 to the General Partner as the holder of 504,851 general partner units.

As discussed in “Note 6. Debt” of these consolidated financial statements, during 2007, the Partnership had a subordinated credit agreement held by a related party of the Partnership, which was repaid in full from a portion of the net proceeds from the IPO.

Prior to the contribution of the Permian Basin Assets to the Partnership in September 2007, the Permian Basin Assets were wholly owned by EAC and these properties were not a separate legal entity. In addition to employee-related expenses, EAC incurred G&A expenses related to leasing office space and other corporate overhead expenses during the period the Permian Basin Assets were wholly owned by EAC. A portion of the consolidated G&A expenses reported for EAC were allocated to the Predecessor and included in the accompanying Consolidated Statements of Operations based on the respective percentage of BOE produced by the Predecessor 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 12.   Subsequent Events

Purchase and Investment Agreement

On December 27, 2007, OLLC entered into a purchase and investment agreement (the “Purchase Agreement”) with Encore Operating. Pursuant to the agreement, OLLC acquired certain oil and natural gas producing properties and related assets in the Permian and Williston Basins. The transaction closed on February 7, 2008 and was effective January 1, 2008.

The total consideration for the acquisition consisted of approximately $125.4 million in cash and 6,884,776 common units representing limited partner interests in the Partnership. Upon completion of the acquisition, the borrowing base under OLLC’s revolving credit facility was increased to $240 million. OLLC financed the cash portion of the purchase price through additional borrowings under the OLLC Credit Agreement.

The acquisition will be accounted for as a transaction between entities under common control. Therefore, the assets will be recorded on the Partnership’s balance sheet at EAC’s historical basis, and the historical results of operations of the Partnership will be restated to reflect the historical operating results of the combined entities.

104

ENCORE ENERGY PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Commodity Derivative Contracts

Subsequent to December 31, 2007, the Partnership increased its oil derivative contract positions by entering into additional commodity derivative contracts. The following tables summarize the Partnership’s open commodity derivative contracts as of February 20, 2008:

Oil Derivative Contracts

	Daily		Average		Daily			Average		Daily		Average		Daily		Average
	Floor		Floor		Short Floor			Short Floor		Cap		Cap		Swap		Swap
Period	Volume		Price		Volume			Price		Volume		Price		Volume		Price
	(Bbl)		(per Bbl)		(Bbl)			(per Bbl)		(Bbl)		(per Bbl)		(Bbl)		(per Bbl)
2008		880		80.00		—			—		440		107.60		—		—
		2,000		75.00		—			—		—		—		—		—
		2,500		65.00		(2,000	)		65.00		—		—		—		—
2009		880		80.00		—			—		440		97.75		—		—
		2,250		75.00		—			—		—		—		—		—
		1,250		63.40		(1,250	)		65.00		—		—		1,000		68.70
2010		880		80.00		—			—		440		93.80		—		—
		2,000		75.00		—			—		1,000		77.23		—		—
		2,000		65.00		(2,000	)		65.00		—		—		—		—
2011		1,880		80.00		—			—		1,440		95.41		—		—
		1,000		70.00		—			—		—		—		—		—

Natural Gas Derivative Contracts

	Daily		Average		Daily		Average
	Floor		Floor		Cap		Cap
Period	Volume		Price		Volume		Price
	(Mcf)		(per Mcf)		(Mcf)		(per Mcf)
2008		3,800		8.20		3,800		9.83
		3,800		7.20		—		—
2009		3,800		8.20		3,800		9.83
		3,800		7.20		—		—
2010		3,800		8.20		3,800		9.58
		3,800		7.20		—		—

Other Events

On January 21, 2008, the Partnership declared a distribution for the fourth quarter of 2007 to unitholders of record as of the close of business on February 6, 2008. Approximately $9.8 million was paid on February 14, 2008 to unitholders at a rate of $0.3875 per unit.

On February 4, 2008, the Partnership entered into interest rate swaps whereby the Partnership swapped $100 million of floating rate debt to a weighted average fixed rate of 3.06 percent. As discussed in “Note 6. Debt,” loans under the OLLC Credit Agreement are subject to a margin in addition to the Eurodollar or base rate of interest, determined 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. Interest determined in accordance with the applicable margin is in addition to the fixed rate entered into in the interest rate swap agreements.

105

ENCORE ENERGY PARTNERS LP

SUPPLEMENTARY INFORMATION

Capitalized Costs and Costs Incurred Relating to Oil and Natural Gas Producing Activities

The capitalized cost of oil and natural gas properties was as follows as of the dates indicated:

	December 31,
	2007			2006
	(In thousands)
Properties and equipment, at cost — successful efforts method:
Proved properties, including wells and related equipment	$	378,170		$	36,414
Accumulated depletion, depreciation, and amortization		(37,661	)		(11,919	)
	$	340,509		$	24,495

The following table summarizes costs incurred related to oil and natural gas properties for the periods indicated:

	Year Ended December 31,
	2007		2006		2005
	(In thousands)
Acquisitions:
Proved properties	$	326,751	$	—	$	—
Asset retirement obligations		5,798		—		—
Total acquisitions		332,549		—		—
Development:
Drilling and exploitation		8,887		1,036		2,180
Asset retirement obligations		28		6		74
Total development		8,915		1,042		2,254
Total costs incurred	$	341,464	$	1,042	$	2,254

Oil & Natural Gas Producing Activities — Unaudited

The estimates of the Partnership’s proved oil and natural gas reserves, which are located entirely within the United States, were prepared in accordance with guidelines established by the Securities and Exchange Commission (“SEC”) and the FASB. Proved oil and natural gas reserve quantities are derived from estimates prepared by Miller and Lents, Ltd., who are independent petroleum engineers.

Future prices received for production and future production costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. There can be no assurance that the proved reserves will be developed within the periods assumed or that prices and costs will remain constant. Actual production may not equal the estimated amounts used in the preparation of reserve projections. In accordance with SEC guidelines, estimates of future net cash flows from ENP’s properties and the representative value thereof are made using oil and natural gas prices in effect as of the dates of such estimates and are held constant throughout the life of the properties. Year-end prices used in estimating net cash flows were as follows as of the dates indicated:

	December 31,
	2007		2006		2005
Oil (per Bbl)	$	96.01	$	61.06	$	61.04
Natural gas (per Mcf)		7.47		5.48		9.44

106

ENCORE ENERGY PARTNERS LP

SUPPLEMENTARY INFORMATION — (Continued)

Net future cash inflows have not been adjusted for commodity derivative contracts outstanding at the end of the year. The future cash flows are reduced by estimated production costs and development costs, which are based on year-end economic conditions and held constant throughout the life of the properties, and by the estimated effect of future income taxes due to the Texas margin tax. Future federal income taxes have not been deducted from future net revenues in the calculation of the Partnership’s standardized measure as each partner is separately taxed on his share of the Partnership’s taxable income.

There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures. Oil and natural gas reserve engineering is and must be recognized as a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in any exact way, and estimates of other engineers might differ materially from those included herein. The accuracy of any reserve estimate is a function of the quality of available data and engineering, and estimates may justify revisions based on the results of drilling, testing, and production activities. Accordingly, reserve estimates are often materially different from the quantities of oil and natural gas that are ultimately recovered. Reserve estimates are integral to management’s analysis of impairments of oil and natural gas properties and the calculation of DD&A on these properties.

Estimated net quantities of proved oil and natural gas reserves of the Partnership were as follows as of the dates indicated:

	December 31,
	2007		2006		2005
Proved reserves:
Oil (MBbls)		14,417		50		45
Natural gas (MMcf)		39,140		37,426		44,190
Combined (MBOE)		20,940		6,288		7,410
Proved developed reserves:
Oil (MBbls)		12,983		50		45
Natural gas (MMcf)		30,515		30,450		31,960
Combined (MBOE)		18,069		5,125		5,372

107

ENCORE ENERGY PARTNERS LP

SUPPLEMENTARY INFORMATION — (Continued)

The changes in proved reserves were as follows for 2007, 2006, and 2005:

				Natural			Oil
	Oil			Gas			Equivalent
	(MBbls)			(MMcf)			(MBOE)
Balance, December 31, 2004		43			40,966			6,871
Extensions and discoveries		—			1,945			324
Revisions of previous estimates		12			3,283			559
Production		(10	)		(2,004	)		(344	)
Balance, December 31, 2005		45			44,190			7,410
Extensions and discoveries		—			402			67
Revisions of previous estimates		12			(5,370	)		(883	)
Production		(7	)		(1,796	)		(306	)
Balance, December 31, 2006		50			37,426			6,288
Acquisitions of minerals-in-place		15,330			2,359			15,724
Extensions and discoveries		70			1,140			260
Revisions of previous estimates		20			84			33
Production		(1,053	)		(1,869	)		(1,365	)
Balance, December 31, 2007		14,417			39,140			20,940

The standardized measure of discounted estimated future net cash flows related to proved oil and natural gas reserves was as follows as of the dates indicated:

	December 31,
	2007			2006			2005
	(In thousands)
Future cash inflows	$	1,348,498		$	198,577		$	377,543
Future production costs		(473,800	)		(57,998	)		(102,129	)
Future development costs		(28,626	)		(10,402	)		(16,284	)
Future abandonment costs, net of salvage		(20,266	)		(476	)		(470	)
Future income tax expense		(4,989	)		(1,288	)		—
Future net cash flows		820,817			128,413			258,660
10% annual discount		(382,456	)		(77,741	)		(132,055	)
Standardized measure of discounted estimated
future net cash flows	$	438,361		$	50,672		$	126,605

108

ENCORE ENERGY PARTNERS LP

SUPPLEMENTARY INFORMATION — (Continued)

The primary changes in the standardized measure of discounted estimated future net cash flows were as follows for the periods indicated:

	Year Ended December 31,
	2007			2006			2005
	(In thousands)
Standardized measure, beginning of year	$	50,672		$	126,605		$	82,722
Net change in prices and production costs		17,831			(53,815	)		42,756
Purchases of minerals-in-place		426,355			—			—
Extensions, discoveries, and improved recovery		5,410			1,040			7,498
Revisions of previous quantity estimates		689			(9,417	)		10,694
Production, net of production costs		(65,763	)		(7,608	)		(13,547	)
Development costs incurred during the period		8,887			1,036			2,180
Accretion of discount		5,067			12,661			8,272
Change in estimated future development costs		(11,378	)		4,846			(7,518	)
Net change in income taxes		(1,895	)		—			—
Change in timing and other		2,486			(24,676	)		(6,452	)
Net increase (decrease)		387,689			(75,933	)		43,883
Standardized measure, end of year	$	438,361		$	50,672		$	126,605

Selected Quarterly Financial Data — Unaudited

The following table sets forth selected quarterly financial data for 2007 and 2006:

	Quarter
	First			Second			Third			Fourth
	(In thousands, except per unit data)
2007
Revenues	$	8,469		$	22,756		$	23,160		$	25,302
Operating income (loss)	$	(1,808	)	$	2,149		$	(3,269	)	$	(10,317	)
Net loss	$	(2,928	)	$	(3,187	)	$	(8,066	)	$	(11,160	)
Net loss allocation (see Note 8):
Limited partners’ interest in net loss							$	(7,597	)	$	(10,960	)
General partner’s interest in net loss							$	(159	)	$	(229	)
Net loss per common unit:
Basic							$	(0.33	)	$	(0.46	)
Diluted							$	(0.33	)	$	(0.46	)
2006
Revenues	$	3,814		$	3,079		$	3,134		$	2,719
Operating income	$	2,538		$	1,896		$	1,898		$	1,438
Net income	$	2,538		$	1,896		$	1,898		$	1,316

The table above presents the allocation of net loss to the limited partners for the period subsequent to the IPO and displays EPU for the applicable periods. For periods prior to the IPO, 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 those periods.

109

ENCORE ENERGY PARTNERS LP

ITEM 9.   CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A.   CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

As of the end of the period covered by this Report, we carried out an evaluation, under the supervision and with the participation of our management, including the Chief Executive Officer and Chief Financial Officer of our general partner, of the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) of the Exchange Act). Based on that evaluation, the Chief Executive Officer and the Chief Financial Officer of our general partner concluded that, as of December 31, 2007, our disclosure controls and procedures were effective to ensure that information required to be disclosed by the Partnership in the reports that it files or submits 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.

This Report does not include a report of management’s assessment regarding internal control over financial reporting or an attestation report of our independent registered public accounting firm due to a transition period established by the rules of the SEC for newly public companies.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting that occurred during the quarter ended December 31, 2007 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

ITEM 9B.   OTHER INFORMATION

None.

PART III

ITEM 10.   DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Encore Energy Partners GP LLC, our general partner and an indirect wholly owned subsidiary of EAC, manages our operations and activities on our behalf. All of the executive management personnel of our general partner are employees of EAC and devote time as needed to conduct our business and affairs. Encore Energy Partners GP LLC has a board of directors that oversees its management, operations, and activities. We refer to the board of directors of Encore Energy Partners GP LLC as the “board of directors of our general partner.” The board of directors and executive officers of our general partner make all strategic decisions on our behalf.

At the closing of our initial public offering, we entered into an amended and restated administrative services agreement with Encore Operating and EAC. Encore Operating performs administrative services for us, 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 us. Encore Operating receives 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. 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. We reimburse EAC for any additional state income, franchise, or similar tax paid by EAC resulting from our

110

ENCORE ENERGY PARTNERS LP

inclusion in a combined state income, franchise, or similar tax report with EAC as required by applicable law. The amount of any such reimbursement will be limited to the tax that we would have paid had we not been included in a combined group with EAC. For more information regarding the amended and restated administrative services agreement, please read “Item 13. Certain Relationships and Related Party Transactions, and Director Independence — Amended and Restated Administrative Services Agreement.”

Our general partner is not elected by our unitholders and will not be subject to re-election on a regular basis in the future. Unitholders are also not entitled to elect the directors of our general partner or directly or indirectly participate in our management or operation. As owner of our general partner, EAC has the ability to elect all the members of the board of directors of our general partner. Our general partner owes a fiduciary duty to our unitholders, although our partnership agreement limits such duties and restricts the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty. Our general partner will be liable, as general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made specifically nonrecourse to it.

Directors and Executive Officers of Our General Partner

The following table sets forth certain information regarding the members of the board of directors and the executive officers of our general partner. Directors are elected for one-year terms by EAC.

Name	Age		Position with Encore Energy Partners GP LLC
I. Jon Brumley		68	Chairman of the Board
Jon S. Brumley		37	Chief Executive Officer, President and Director
Robert C. Reeves		38	Senior Vice President, Chief Financial Officer and Treasurer
L. Ben Nivens		47	Senior Vice President and Chief Operating Officer
John W. Arms		40	Senior Vice President, Acquisitions
Philip D. Devlin		63	Senior Vice President, General Counsel and Secretary
Kevin Treadway		42	Senior Vice President, Land
Andrea Hunter		33	Vice President, Controller and Principal Accounting Officer
Thomas H. Olle		53	Vice President, Mid-Continent Region
Diane K. Weaver		53	Vice President, Investor Relations
Arnold L. Chavkin		56	Director
John E. Jackson		49	Director
J. Luther King, Jr.		67	Director
Clayton E. Melton		64	Director
George W. Passela		62	Director

The directors of our general partner hold office until the earlier of their death, resignation, removal, or disqualification or until their successors have been elected and qualified. Officers of our general partner serve at the discretion of the board of directors of our general partner.

I. Jon Brumley has been Chairman of the Board of our general partner since February 2007. Mr. Brumley is currently Chairman of the Board of EAC, a position he has held since its inception in April 1998. He also served as Chief Executive Officer of EAC from its inception until December 2005 and President of EAC from its inception until August 2002. Beginning in August 1996, Mr. Brumley served as Chairman and Chief Executive Officer of MESA Petroleum (an independent oil and gas company) until MESA’s merger in August 1997 with Parker & Parsley to form Pioneer Natural Resources Company (an independent oil and gas company). He served as Chairman and Chief Executive Officer of Pioneer until joining EAC in 1998.

111

ENCORE ENERGY PARTNERS LP

Mr. Brumley has also served as Chairman of XTO Energy, Inc. and President and Chief Executive Officer of Southland Royalty Company. Mr. Brumley received a Bachelor of Business Administration from the University of Texas and a Master of Business Administration from the University of Pennsylvania Wharton School of Business. He is the father of Jon S. Brumley.

Jon S. Brumley has been the Chief Executive Officer, President and Director of our general partner since February 2007. Mr. Brumley has been Chief Executive Officer of EAC since January 2006, President of EAC since August 2002, and a director of EAC since November 2001. He also held the positions of Executive Vice President — Business Development and Corporate Secretary from EAC’s inception in April 1998 until August 2002 and was a director of EAC from April 1999 until May 2001. Prior to joining EAC, Mr. Brumley held the position of Manager of Commodity Risk and Commercial Projects for Pioneer Natural Resources Company. He was with Pioneer since its creation by the merger of MESA and Parker & Parsley in August 1997. Prior to August 1997, Mr. Brumley served as Director — Business Development for MESA. Mr. Brumley received a Bachelor of Business Administration in Marketing from the University of Texas. He is the son of I. Jon Brumley.

Robert C. Reeves has been the Senior Vice President, Chief Financial Officer and Treasurer of our general partner since February 2007. Mr. Reeves has been Senior Vice President, Chief Financial Officer and Treasurer of EAC since November 2006. From November 2006 until January 2007, Mr. Reeves also served as Corporate Secretary of EAC. Mr. Reeves served as Senior Vice President, Chief Accounting Officer, Controller and Assistant Corporate Secretary of EAC from November 2005 until November 2006. He served as EAC’s Vice President, Controller and Assistant Corporate Secretary from August 2000 until October 2005. He served as Assistant Controller of EAC from April 1999 until August 2000. Prior to joining EAC, Mr. Reeves served as Assistant Controller for Hugoton Energy Corporation. Mr. Reeves received his Bachelor of Science degree in Accounting from the University of Kansas. He is a Certified Public Accountant.

L. Ben Nivens has been the Senior Vice President and Chief Operating Officer of our general partner since February 2007. Mr. Nivens has been Senior Vice President and Chief Operating Officer of EAC since November 2006. From November 2005 until November 2006, Mr. Nivens served as Senior Vice President, Chief Financial Officer, Treasurer and Corporate Secretary of EAC. Mr. Nivens served as EAC’s Vice President of Corporate Strategy and Treasurer from June 2005 until October 2005. From April 2002 to June 2005, Mr. Nivens served as engineering manager and in other engineering positions for EAC. Prior to joining EAC, he worked as a reservoir engineer for Prize Energy from 1999 to 2002. From 1990 to 1999, Mr. Nivens worked in the corporate planning group at Union Pacific Resources and also served as a reservoir engineer. In addition, he worked as a reservoir engineer for Compass Bank in 1999. Mr. Nivens received a Bachelor of Science in Petroleum Engineering from Texas Tech University and a Masters of Business Administration from Southern Methodist University.

John W. Arms has been the Senior Vice President — Acquisitions of our general partner since February 2007. Mr. Arms has served as Senior Vice President — Acquisitions of EAC since February 2007. Mr. Arms served as Vice President of Business Development of EAC from September 2001 until February 2007. From November 1998 until September 2001, Mr. Arms served in various petroleum engineering positions for EAC. Prior to joining EAC in November 1998, Mr. Arms was a Senior Reservoir Engineer for Union Pacific Resources and an Engineer at XTO Energy, Inc. Mr. Arms received a Bachelor of Science in Petroleum Engineering from the Colorado School of Mines.

Philip D. Devlin has been the Senior Vice President, General Counsel and Secretary of our general partner since February 2007. Mr. Devlin has served as Senior Vice President, General Counsel and Corporate Secretary of EAC since January 2007. From March 1997 until January 2007, Mr. Devlin served as Vice President, General Counsel and Secretary of National Energy Group, Inc., formerly a publicly traded management company engaged in the business of managing the exploration, development, production, and operations of oil and natural gas properties. From October 1994 through February 1997, he served as President and Chief Executive Officer of Sunrise Energy Services, Inc. From September 1984 through October 1994, he

112

ENCORE ENERGY PARTNERS LP

served as Executive Vice President, General Counsel and Secretary of Sunrise Energy Services, Inc. He is licensed by the State Bar of Texas, admitted to practice before the Supreme Court of the United States and is a past President and Director of the Natural Gas and Electric Power Association of North Texas. Mr. Devlin earned a Bachelor of Arts degree and a Master of Arts degree from the University of California, and a Juris Doctor degree with honors from California Western School of Law, San Diego, California.

Kevin Treadway has been the Senior Vice President — Land of our general partner and EAC since February 2008. From 2004 until February 2008, Mr. Treadway served as Vice President — Land of EAC. He joined EAC in 2000 as staff landman and in 2002 was promoted to Land Manager. Prior to joining EAC, Mr. Treadway served as a Landman at Coho Resources. Mr. Treadway received a Bachelor of Science degree in Petroleum Land Management from the University of Southwestern Louisiana.

Andrea Hunter has been Vice President, Controller and Principal Accounting Officer of our general partner and EAC since February 2008. Prior to her promotion, Ms. Hunter had served as Controller of our general partner and EAC since September 2007. From July 2003 to September 2007, Ms. Hunter held positions of increasing responsibility at EAC, including financial reporting senior manager. Prior to joining EAC in July 2003, Ms. Hunter worked in public accounting, first in the Assurance and Business Advisory Services of PricewaterhouseCoopers LLP and later as an editor at Thomson Publishing’s Practitioners Publishing Company. Ms. Hunter received a Master of Science and Bachelor of Business Administration, both in Accounting, from the University of Texas at Arlington. She is a Certified Public Accountant.

Thomas H. Olle has been Vice President, Mid-Continent Region of our general partner since February 2007. Mr. Olle has been Vice President, Mid-Continent Region of EAC since November 2006. Mr. Olle held the position of Senior Vice President, Asset Management of EAC from April 2003 to November 2006. Mr. Olle joined EAC in March 2002 as Vice President of Engineering. Prior to joining EAC, Mr. Olle served as Senior Engineering Advisor of Burlington Resources, Inc. from September 1999 to March 2002. From July 1989 to September 1999 he served as Regional Engineer of Burlington Resources. Mr. Olle is a 1976 graduate of the University of Texas at Austin and holds a Bachelor of Science degree with Highest Honors in Mechanical Engineering.

Diane K. Weaver has been Vice President, Investor Relations of our general partner since February 2008. Ms. Weaver has been Vice President, Investor Relations of EAC since August 2007. Prior to joining EAC, Ms. Weaver served as Director of Investor Relations for Quicksilver Resources Inc. from December 2003 to August 2007. From January 2001 to December 2003, Ms. Weaver served as Senior Financial Reporting Accountant for XTO Energy, Inc. Prior to January 2001, Ms. Weaver worked at Union Pacific Resources Company and Sohio Petroleum Company.

Arnold L. Chavkin has been a director of our general partner since October 2007 and is the chairman of the audit committee of the Board of Directors. Mr. Chavkin is also a member of the conflicts committee of the Board of Directors. Mr. Chavkin is currently a managing director at Pinebrook Road Partners, a private equity fund. From 1991 until his retirement in 2006, he served in various capacities with JPMorgan Chase & Co, including as the Chief Investment Officer at J.P. Morgan Partners, LLC. Prior to that, Mr. Chavkin was a member of Chemical Bank’s merchant banking and corporate finance groups, specializing in mergers and acquisitions and private placements for the energy industry. Mr. Chavkin served as a director of Encore Acquisition Company from 1998 to 2004. Mr. Chavkin is a Certified Public Accountant. He received a Bachelor of Arts degree and a Masters of Business Administration from Columbia University.

John E. Jackson has been a director of our general partner since February 2008. Mr. Jackson is currently Chairman, Chief Executive Officer and President of Price Gregory Services, Inc., a pipeline-related infrastructure service provider in North America. Mr. Jackson was President, Chief Executive Officer and a director of Hanover Compressor Company from October 2004 until August 2007 when Hanover merged with Universal Compression Holdings, Inc. Mr. Jackson joined Hanover in January 2002 as a Senior Vice President and Chief Financial Officer. Previously, Mr. Jackson was Vice President and Chief Financial Officer of Duke Energy Field Services, a producer and marketer of natural gas liquids. Prior to joining Duke Energy Field

113

ENCORE ENERGY PARTNERS LP

Services, Mr. Jackson served in a variety of treasury, controller and accounting positions at Union Pacific Resources. Mr. Jackson is currently a director of Exterran Holdings, Inc. and Seitel Inc.

J. Luther King, Jr. has been a director of our general partner since August 2007. Mr. King is the President of Luther King Capital Management Corporation, a registered investment advisory firm that he founded in 1979, and has served as President and Trustee of LKCM Funds, a registered investment company, since 1994. Mr. King serves as a director of Tyler Technologies, Inc. and is a member of its Audit Committee. In addition, Mr. King serves as the chairman of the board of trustees of Texas Christian University. Mr. King has a Bachelor of Science degree and a Masters of Business Administration from Texas Christian University and is a Chartered Financial Analyst.

Clayton E. Melton has been a director of our general partner since August 2007. Mr. Melton has served as President of Atlantic Service & Supply LLC, a distributor of heating and air conditioning equipment located in Fort Worth, Texas, since January 2003. From May 1999 to December 2002, he served as President of Comfort Products L.L.C., an air conditioning and heating distribution company. Prior to May 1999, Mr. Melton held various leadership and management positions in his over 33 years of service in the U.S. Army obtaining the rank of Brigadier General. Mr. Melton received a Bachelor of Science in Business Administration from William Carey College and a Masters of Public Administration from the University of Missouri.

George W. Passela has been a director of our general partner since August 2007. Mr. Passela is currently the Chief Financial Officer of Momentum Energy Group LLC, a natural gas gathering, compression, treating, and processing company. Prior to joining Momentum Energy, Mr. Passela was Managing Director at Banc of America Securities LLC, with responsibility for capital raising and investments in the exploration and production and midstream sectors. From 1977 until 2005, Mr. Passela was employed by The First National Bank of Boston in its International Division, initially working with multinational corporations that provided export and commodity financing in South America. From 1982 until 1987, he served as Branch Manager in Frankfurt, Germany. Upon returning to Boston, Mr. Passela established The First National Bank of Boston’s exploration and production practice and held various management positions in its energy group through 2005. Mr. Passela holds a Bachelor of Arts degree from the University of Miami and a Masters of Business Administration from the University of Utah.

Director Independence

The board of directors of our general partner has seven members, none of whom are officers or employees of EAC and its affiliates, including our general partner, other than Mr. I. Jon Brumley and Mr. Jon S. Brumley. The board of directors of our general partner has determined that Messrs. Chavkin, King, Melton, and Passela are independent, as defined for purposes of the listing standards of the NYSE. In making this determination, the board of directors of our general partner affirmatively determined that each independent director had no material relationship with EAC and its affiliates, including our general partner (either directly or as a partner, shareholder, or officer of an organization that has a relationship with EAC and its affiliates, including our general partner), and that none of the express disqualifications contained in the NYSE rules applied to any of them.

As contemplated by NYSE rules, the board of directors of our general partner has adopted categorical standards to assist it in making independence determinations, under which relationships that fall within the categorical standards are not required to be disclosed in this Report and their impact on independence need not be separately discussed. The board of directors of our general partner, however, considers all material relationships with each director in making its independence determinations. A relationship falls within the categorical standards if it:

•  Is a type of relationship addressed in Item 404 of Regulation S-K under the Securities Exchange Act of 1934 or Section 303A.02(b) of the NYSE Listed Company Manual, but under those rules neither requires disclosure nor precludes a determination of independence; or

114

ENCORE ENERGY PARTNERS LP

•  Consists of charitable contributions by EAC and its affiliates, including our general partner to an organization where a director is an executive officer and does not exceed the greater of $1 million or 2% of the organization’s gross revenue in any of the last three years.

None of the independent directors had relationships relevant to an independence determination that were outside the scope of the categorical standards.

The NYSE does not require a listed limited partnership like us to have a majority of independent directors on the board of directors of our general partner or to establish a compensation committee or a nominating and corporate governance committee.

Board Committees

As of February 20, 2008, the board of directors of our general partner had an audit and conflicts committee. The following table sets forth the membership on each committee:

Name of Director	Audit	Conflicts
Arnold L. Chavkin	Chair	ü
John E. Jackson
J. Luther King, Jr.	ü	ü
Clayton E. Melton	ü	ü
George W. Passela	ü	Chair

The audit committee held one meeting in 2007, the conflicts committee held five meetings in 2007, and the board of directors of our general partner held five meetings in 2007. Each director attended at least 75 percent of all board and applicable committee meetings in 2007.

Audit Committee.  The audit committee’s purpose is, among other things, to assist the board of directors of our general partner in overseeing:

•  the integrity of our financial statements;

•  our compliance with legal and regulatory requirements;

•  the independence, qualifications, and performance of our independent registered public accounting firm; and

•  the performance of our internal audit function.

The board of directors of our general partner has determined that all 4 members of the audit committee are independent under the listing standards of the NYSE and the rules of the SEC. In addition, the board of directors of our general partner has determined that Mr. Chavkin is an “audit committee financial expert” as such term is defined in Item 407(d)(5) of Regulation S-K under the Exchange Act.

The charter of the audit committee is available on the “Corporate Governance” section of our website at www.encoreenp.com.  Unitholders may request free printed copies of the audit committee charter from the following address:

Encore Energy Partners GP LLC
Attention: Corporate Secretary
777 Main Street, Suite 1400
Fort Worth, Texas 76102
(817) 877-9955

Conflicts Committee.  The conflicts committee reviews specific matters that the board of directors believes may involve conflicts of interest. At the request of the board of directors, the conflicts committee determines if the resolution of the conflict of interest is fair and reasonable to us. The members of the

115

ENCORE ENERGY PARTNERS LP

conflicts committee may not be officers or employees of our general partner or directors, officers, or employees of its affiliates, including EAC, and must meet the independence and experience standards established by the NYSE Listed Company Manual and the Securities Exchange Act of 1934 to serve on an audit committee of a board of directors, and certain other requirements. Any matters approved by the conflicts committee in good faith will be conclusively deemed to be fair and reasonable to us, approved by all of our partners and not a breach by our general partner of any duties it may owe us or our unitholders.

Code of Business Conduct and Ethics and Governance Guidelines

We have adopted a Code of Business Conduct and Ethics covering our directors, officers, and employees, which is available free of charge on the “Corporate Governance” section of our website (www.encoreenp.com). We will post on our website any amendments to the Code of Business Conduct and Ethics or waivers of the Code of Business Conduct and Ethics for directors and executive officers.

In addition, we have adopted Governance Guidelines, which address director qualification standards; director responsibilities; director access to management, and as necessary and appropriate, independent advisors; director compensation; director orientation and continuing education; and annual performance evaluation of the board of directors. The Governance Guidelines are available free of charge on the “Corporate Governance” section of our website (www.encoreenp.com).

Unitholders may request free printed copies of the Code of Business Conduct and Ethics and Governance Guidelines from the following address:

Encore Energy Partners GP LLC
Attention: Corporate Secretary
777 Main Street, Suite 1400
Fort Worth, Texas 76102
(817) 877-9955

NYSE Corporate Governance Listing Standards

We have filed the required certifications under Section 302 of the Sarbanes-Oxley Act of 2002 as Exhibits 31.1 and 31.2 to this Report. We plan to submit to the NYSE the CEO certification required by Section 303A.12(a) of the NYSE’s Listed Company Manual within thirty days after filing this Report.

Executive Sessions of Non-Management Directors

The board of directors holds regular executive sessions in which non-management directors meet without any members of management present. Arnold L. Chavkin, John E. Jackson, J. Luther King, Jr., Clayton E. Melton, and George W. Passela are non-management directors of our general partner and Messrs. Chavkin, King, Melton, and Passela are independent under applicable NYSE rules. The purpose of these executive sessions is to promote open and candid discussion among the non-management directors. The chairman of the audit committee acts as chair of such executive sessions.

In accordance with NYSE rules, we have established a toll-free, confidential telephone hotline (the “Hotline”) so that interested parties may communicate with the presiding director or with all the non-management directors as a group. All calls to this Hotline are reported to the chairman of the audit committee, who is responsible for communicating any necessary information to the other non-management directors. The number of our confidential Hotline is (866) 783-5389.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Exchange Act requires directors and executive officers of our general partner and holders of more than 10 percent of our common units to file with the SEC reports regarding their ownership and changes in ownership of our securities. We believe that, during 2007, the directors and executive officers

116

ENCORE ENERGY PARTNERS LP

of our general partner and our 10 percent unitholders complied with all Section 16(a) filing requirements, except that a Form 5 for Mr. I. Jon Brumley was filed late. In making these statements, we have relied upon examination of the copies of Forms 3, 4 and 5 provided to us and the written representations of the directors and executive officers of our general partner.

ITEM 11.   EXECUTIVE COMPENSATION

Compensation Discussion and Analysis

General

We do not employ any of the persons responsible for managing our business, and we do not have a compensation committee. Our general partner manages our operations and activities, and its board of directors and officers make decisions on our behalf. All of the executive officers of our general partner also serve as executive officers of EAC. The compensation of EAC’s employees that perform services on our behalf (other than the long-term incentive plan benefits described below) are set by the compensation committee of, and paid for, by EAC. We do not expect to pay any salaries or bonuses, or to make awards under our long-term incentive plan, to the current named executive officers of the general partner for so long as the management incentive units remain outstanding.

Management Incentive Units

General

In May 2007, the board of directors of our general partner granted management incentive units to certain executive officers of our general partner. A management incentive unit is a limited partner interest in our partnership that entitles the holder to quarterly distributions to the extent paid to our common unitholders and to increasing distributions upon the achievement of 10 percent compounding increases in our distribution rate to common unitholders.

As of February 20, 2008, the management incentive units represented an approximately 2.1 percent interest in our partnership (assuming conversion of the management incentive units based on the then-current distribution rate) and were entitled to approximately 2.1 percent of our aggregate annual distributions (or approximately $1.1 million in the aggregate). 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 our then-outstanding units; and

•  the holders of management incentive units are not entitled to receive, in the aggregate, distributions of our available cash in an amount that exceed a maximum limit of 5.1 percent of all such distributions to all unitholders at the time of any such distribution.

If the 5.1 percent maximum limit on aggregate distributions to the holders of our management incentive units is reached, then any available cash that would have been distributed to such holders will be available for distribution to our unitholders.

In addition to approval by the board of directors of our general partner, the grants of management incentive units were approved by EAC’s Board of Directors based on the recommendation of its compensation committee, which consists of James A. Winne III, Martin C. Bowen, and Ted Collins, Jr. The management incentive units are based on the performance of our partnership and are intended to align the economic interests of our general partner’s executives with the interests of our unitholders; that is, annual distribution increases and capital appreciation for management of our general partner are tied directly to annual distribution increases and capital appreciation for our public unitholders. In making its decision to approve the grant of

117

ENCORE ENERGY PARTNERS LP

management incentive units by the board of directors of our general partner, EAC’s Board of Directors and its compensation committee relied on, among other things, the advice of an independent compensation consultant retained by the compensation committee, as well as analyses of equity compensation and ownership by other executives of master limited partnerships.

The management incentive units were issued based on the assumption that we would not pay the recipients any salaries or bonuses, or grant them any awards under our long-term incentive plan, while such units are outstanding.

In the future, the management incentive units could represent up to a maximum of 5.1 percent of the aggregate number of units then outstanding on a fully diluted basis and could be entitled to up to a maximum of 5.1 percent of aggregate annual distributions to all units then outstanding. These estimates are based on numerous assumptions, including, without limitation, the following:

•  our expectation that we will acquire additional oil and natural gas properties at pricing metrics comparable to the price we paid for the Elk Basin assets in March 2007, and that such acquisitions would be accretive by 10 percent in then-current distributions per common unit;

•  our expectation that we will finance the acquisition of additional oil and natural gas properties by using 50 percent debt and 50 percent equity in the form of new common units, until our ratio of total long-term debt to Adjusted EBITDA is 2.25 to 1.0, at which point we will fund such acquisitions entirely with equity in the form of new common units;

•  our expectation that new common units will be valued at prices reflecting the then-current distribution rate per common unit and a fixed yield;

•  our expectation that we will not be able to increase our distribution rate without issuing additional common units to make acquisitions; and

•  our cash available for distribution will equal at least 110 percent of our distributions on a rolling four quarter basis.

The following table sets forth the recipients of the management incentive units:

	Number of Management
Name and Position with Encore Energy Partners GP LLC	Incentive Units
I. Jon Brumley (Chairman of the Board)		143,000
Jon S. Brumley (Chief Executive Officer, President and Director)		143,000
Robert C. Reeves (Senior Vice President, Chief Financial Officer and Treasurer)		110,000
L. Ben Nivens (Senior Vice President and Chief Operating Officer)		77,000
John W. Arms (Senior Vice President, Acquisitions)		77,000
Total		550,000

Vesting

Management incentive units vest in three equal installments on September 17, 2007, 2008 and 2009. The holder of a management incentive unit does not have any voting rights with respect to that unit. The holder of a management incentive unit may transfer the unit to a permitted transferee, but such units are not otherwise transferable until such units convert into common units.

If a holder ceases to be employed by EAC or its affiliates other than by reason of death, disability, or a change in control, then the holder will continue to own the management incentive units to the extent vested, which will be subject to the same terms and conditions as if such employment had not ceased. After a holder ceases to be employed by EAC or its affiliates, we have the right, in our sole discretion, to convert the management incentive units to common units.

118

ENCORE ENERGY PARTNERS LP

Distributions

The following table sets forth the aggregate distributions to the holders of management incentive units based on growth in per unit distributions to our unitholders:

•  Annualized Distribution per Common Unit:  In order for distributions payable to the holders of the management incentive units to increase, the distributions payable to our unitholders must increase by 10 percent on a compounded basis;

•  Annualized Distribution per Management Incentive Unit:  After distributions payable to our unitholders have increased by 10 percent on a compounded basis, the holders of management incentive units will be entitled to increased distributions per unit on any outstanding management incentive units; and

•  Aggregate Annualized Distributions to Management:  The aggregate annualized distributions to management are determined by multiplying the annualized distribution per management incentive unit by 550,000, provided that aggregate distributions on all management incentive units are subject to a maximum limit of 5.1 percent of all distributions to our unitholders.

Annualized Management Incentive Units
Distribution Summary

Common Units				Management Incentive Units
Annualized				Annualized		Aggregate
Distribution per		Percentage		Distribution per		Annualized
Unit(a)		Increase		Unit(a)		Distributions
$	1.40		—	$	1.40	$	770,000
$	1.54		10.0%	$	1.93	$	1,058,750
$	1.69		10.0%	$	2.65	$	1,455,781
$	1.86		10.0%	$	3.64	$	2,001,674
$	2.05		10.0%	$	5.00	$	2,752,329
$	2.25		10.0%	$	6.88	$	3,784,515
$	2.48		10.0%	$	9.46	$	5,203,640
$	2.73		10.0%	$	13.01	$	7,155,042

(a) Numbers are approximate due to rounding.

Conversion

Management incentive units are convertible into our common units upon the occurrence of any of the following events:

•  a change in control (defined below);

•  at the option of the holder, when our aggregate quarterly distributions to common unitholders over four consecutive quarters are at least $2.05 per unit; or

•  the holder’s death or disability.

A management incentive unit was initially convertible into one common unit. The conversion rate per management incentive unit is equal to (x) the annualized distribution rate per management incentive unit immediately prior to conversion divided by (y) the annualized distribution rate per common unit. The actual number of common units issued to a holder of management incentive units upon conversion is designed to achieve “distribution parity” between the management incentive units being converted and the common units being received.

119

ENCORE ENERGY PARTNERS LP

If we make distributions per common unit of at least $2.05 over a period of four consecutive quarters, then a holder of management units will have the option to convert his or her management incentive units into common units at a conversion ratio of 2.4414 common units per management incentive unit.

The following table sets forth the aggregate number of common units into which the management incentive units are convertible:

•  Annualized Distribution per Common Unit:  In order for distributions payable to the holders of the management incentive units to increase, the distributions payable to our unitholders must increase by 10 percent on a compounded basis;

•  Conversion Rate per Management Incentive Unit:  After distributions payable to our unitholders have increased by 10 percent on a compounded basis, the holders of management incentive units will be entitled to an increasing number of common units upon conversion of each management incentive unit. In general, the management incentive units are not convertible until we make distributions per common unit of at least $2.05 over a period of four consecutive quarters; and

•  Common Unit Equivalent Management Incentive Units:  The aggregate number of common units into which the management incentive units are convertible is determined by multiplying the conversion rate per management incentive unit by 550,000.

Annualized Management Incentive Units
Conversion Summary

Common Units					Management Incentive Units
Annualized					Conversion
Distribution per		Percentage			Rate per		Common Unit
Unit(a)		Increase			Unit(a)		Equivalents
$	1.40		—			1.0000		550,000
$	1.54		10.0	%		1.2500		687,500
$	1.69		10.0	%		1.5625		859,375
$	1.86		10.0	%		1.9531		1,074,205
$	2.05		10.0	%		2.4414		1,342,770
$	2.25		10.0	%		3.0518		1,678,490
$	2.48		10.0	%		3.8147		2,098,085
$	2.73		10.0	%		4.7684		2,622,620

(a) Numbers are approximate due to rounding.

Upon conversion, the holders of management incentive units will not be entitled to receive, in the aggregate, common units in excess of 5.1 percent of all of our outstanding units on a fully diluted basis. For one year after the conversion date, the holders of such units may receive additional common units upon the issuance of additional partnership securities on a pro rata basis up to the maximum limit of 5.1 percent of all then outstanding units on a fully diluted basis.

After the conversion of management incentive units at the 4.7684 conversion rate as described above, the management incentive units will automatically cease to exist. Thereafter and in its sole discretion, the conflicts committee may or may not issue additional management incentive units. If the conflicts committee decides to issue such units, it may issue up to 550,000 management incentive units to persons selected by the conflicts committee. The new management incentive units will have an initial distribution rate of not less than $2.73 per management incentive unit and an initial conversion rate of 1.0. The initial distribution rate and the conversion rate for the new management incentive units will increase in the same proportion as the initial distribution rate and the conversion rate on the initial management incentive units.

120

ENCORE ENERGY PARTNERS LP

If the holder of a management incentive unit ceases to be an employee of EAC and its affiliates, and the management incentive units held by such person ultimately convert into common units as described above, then the management incentive units previously held by such person will be available for grant to another employee, subject to the approval of the conflicts committee.

Change in Control

For purposes of the management incentive units, a change in control of our general partner is defined as the occurrence of one or more of the following events:

•  a “Change in Control” as defined in EAC’s 2000 Incentive Stock Plan;

•  any person or group, other than EAC and its affiliates, becomes the beneficial owner, by way of merger, consolidation, recapitalization, reorganization or otherwise, of 50 percent or more of the combined voting power of the equity interests in the general partner or our partnership;

•  our limited partners approve, in one or a series of transactions, a plan of complete liquidation of our partnership;

•  the sale or other disposition by either our general partner or our partnership of all or substantially all of its assets in one or more transactions to any person other than the general partner or an affiliate of the general partner; or

•  a transaction resulting in a person other than Encore Energy Partners GP LLC or one of its affiliates being the general partner of our partnership.

121

ENCORE ENERGY PARTNERS LP

Compensation Committee Report

Neither we nor our general partner has a compensation committee. The board of directors of our general partner has reviewed and discussed the Compensation Discussion and Analysis set forth above with management and based on this review and discussion has approved it for inclusion in this Form 10-K.

The board of directors of Encore Energy
Partners GP LLC:

I. Jon Brumley, Jon S. Brumley, Arnold L. Chavkin, John E. Jackson, J. Luther King, Jr.,

Clayton E. Melton and George W. Passela

Summary Compensation Table

The following table summarizes the total compensation awarded to, earned by, or paid to our named executive officers with respect to 2007:

													Change in Pension
													Value and
													Nonqualified
							Stock				Non-Equity		Deferred
							Awards		Option		Incentive Plan		Compensation		All Other
	Year		Salary		Bonus		(a)		Awards		Compensation		Earnings		Compensation		Total
I. Jon Brumley		2007		—		—	$	1,769,074		—		—		—		—	$	1,769,074
Chairman of the Board		2006		—		—		—		—		—		—		—		—
Jon S. Brumley		2007		—		—	$	1,769,074		—		—		—		—	$	1,769,074
Chief Executive Officer and President		2006		—		—		—		—		—		—		—		—
Robert C. Reeves		2007		—		—	$	1,360,826		—		—		—		—	$	1,360,826
Senior Vice President, Chief Financial Officer and Treasurer		2006		—		—		—		—		—		—		—		—
L. Ben Nivens		2007		—		—	$	952,578		—		—		—		—	$	952,578
Senior Vice President and Chief Operating Officer		2006		—		—		—		—		—		—		—		—
John W. Arms		2007		—		—	$	952,578		—		—		—		—	$	952,578
Senior Vice President, Acquisitions		2006		—		—		—		—		—		—		—		—

(a) Reflects the compensation cost recognized by us under SFAS 123R for the grant of management incentive units in 2007. Pursuant to SEC rules, the amounts shown exclude the impact of estimated forfeitures related to service-based vesting conditions. These amounts reflect our recognized compensation expense for these awards under SFAS 123R, and do not correspond to the actual value that will be recognized by the named executive officers. For information on the assumptions in the valuation of the management incentive units, please read Note 9 of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data.”

122

ENCORE ENERGY PARTNERS LP

Grants of Plan-Based Awards for 2007

The following table contains information with respect to the grant of management incentive units to the named executive officers in 2007.

			Estimated Future Payouts Under
			Equity Incentive Plan Awards(a)						Grant Date
			Threshold		Target		Maximum		Fair Value
	Grant Date		(#)(b)		(#)(c)		(#)(d)		Awards(e)
I. Jon Brumley		May 10, 2007		143,000		349,120		681,881	$	3,005,860
Jon S. Brumley		May 10, 2007		143,000		349,120		681,881	$	3,005,860
Robert C. Reeves		May 10, 2007		110,000		268,554		524,524	$	2,312,200
L. Ben Nivens		May 10, 2007		77,000		187,988		367,167	$	1,618,540
John W. Arms		May 10, 2007		77,000		187,988		367,167	$	1,618,540

(a)	A management incentive unit is a limited partner interest in our partnership that entitles the holder to quarterly distributions to the extent paid to our common unitholders and to increasing distributions upon the achievement of 10 percent compounding increases in our distribution rate to common unitholders. The distribution rate per management incentive unit ranges from $1.40 to $13.01. The conversion rate per management incentive unit will be equal to (x) the annualized distribution rate per management incentive unit immediately prior to conversion divided by (y) the annualized distribution rate per common unit. The actual number of common units issued to a holder of management incentive units upon conversion is designed to achieve “distribution parity” between the management incentive units being converted and the common units being received. A management incentive unit was initially convertible into one common unit and, at February 20, 2008, was convertible at a rate of 1.25 common units per management incentive unit. Management incentive units vest in three equal installments on September 17, 2007, 2008 and 2009. The holder of a management incentive unit does not have any voting rights with respect to that unit. For more information on the management incentive units, please read “Compensation Discussion and Analysis — Management Incentive Units.”
(b)	Represents the initial conversion rate of one common unit per management incentive unit.
(c)	Represents a conversion rate of 2.4414 common units per management incentive unit.
(d)	Represents a conversion rate of 4.7684 common units per management incentive unit.
(e)	The grant date fair value of each award has been computed in accordance with SFAS 123R.

123

ENCORE ENERGY PARTNERS LP

Outstanding Equity Awards at Fiscal Year End

The following table sets forth summary information regarding management incentive units held by each of the named executive officers of our general partner at December 31, 2007:

	Unit Awards
			Equity Incentive
			Plan Awards:
	Equity Incentive		Market or
	Plan Awards:		Payout Value
	Number of		of Unearned
	Unearned Shares,		Shares, Units
	Units or Other		or Other Rights
	Rights That Have		That Have Not
	Not Vested (#)		Vested ($)
Name	(a)(b)		(c)
I. Jon Brumley		95,333	$	2,145,000
Jon S. Brumley		95,333		2,145,000
Robert C. Reeves		73,333		1,650,000
L. Ben Nivens		51,333		1,155,000
John W. Arms		51,333		1,155,000

(a)	Represents the number of unvested management incentive units held by the executive officers of our general partner as of December 31, 2007. Management incentive units vest in three equal installments on September 17, 2007, 2008, and 2009.
(b)	As of December 31, 2007, each management incentive unit represented 1.25 common unit equivalents. For more information on the conversion rate per management incentive unit, please read “Compensation Discussion and Analysis — Management Incentive Units — Conversion.”
(c)	Represents the product of the closing price of our common units on December 31, 2007 ($18.00) multiplied by the number of common unit equivalents that the management incentive units represent as of December 31, 2007 (1.25).

Units Vested

The following table summarizes the vesting of management incentive units reflected in the tables above held by each of the named executive officers of our general partner as of December 31, 2007:

	Unit Awards
	Number of Units
	Acquired on		Value Realized
	Vesting		on Vesting
Name	(a)		(b)
I. Jon Brumley		47,667	$	1,043,907
Jon S. Brumley		47,667		1,043,907
Robert C. Reeves		36,667		803,007
L. Ben Nivens		25,667		562,107
John W. Arms		25,667		562,107

(a)

Represents the number of management incentive units held by the executive officers of our general partner that vested on September 17, 2007.

(b)

Represents the product of the closing price of a common unit of ENP on the vesting date of the management incentive units, September 17, 2007, ($21.90) multiplied by the number of common unit equivalents that the management incentive units represented as of September 17, 2007 (1.0). For more information on the conversion rate per management incentive unit, please read “Compensation Discussion and Analysis — Management Incentive Units — Conversion.”

124

ENCORE ENERGY PARTNERS LP

Pension Benefits

We do not maintain any plans that provide for payments or other benefits at, following or in connection with retirement.

Non-Qualified Deferred Compensation

We do not maintain any defined contribution or other plan that provides for the deferral of compensation on a basis that is not tax-qualified under the Code.

Potential Payments Upon Termination or Change-in-Control

The following table shows the potential value of the management incentive units to our named executive officers as of December 31, 2007 in the event of a termination of employment.

	I. Jon Brumley		Jon S. Brumley		Robert C. Reeves		L. Ben Nivens		John W. Arms
Death of Executive(a)(b)	$	3,217,500	$	3,217,500	$	2,475,000	$	1,732,500	$	1,732,500
Disability of Executive(a)(b)	$	3,217,500	$	3,217,500	$	2,475,000	$	1,732,500	$	1,732,500
Change in Control of Us(a)(b)	$	3,217,500	$	3,217,500	$	2,475,000	$	1,732,500	$	1,732,500
Any other termination(a)(c)	$	1,072,508	$	1,072,508	$	825,008	$	577,508	$	577,508

(a)	The payment to an executive is determined by multiplying the number of common unit equivalents represented by the executive’s management incentive units by the closing price of our common units on the New York Stock Exchange on December 31, 2007 ($18.00).
(b)	Upon the death or disability of the executive, or a change in control of our partnership, all management incentive units will immediately vest.
(c)	Upon a voluntary termination by the executive or a termination of the executive with or without cause by us, the executive will continue to own the management incentive units to the extent vested, which will be subject to the same terms and conditions as if such employment had not ceased. After an executive ceases to be employed by EAC or its affiliates, we have the right, in our sole discretion, to convert the management incentive units to common units.

Compensation Committee Interlocks and Insider Participation

As previously discussed, our general partner’s board of directors is not required to maintain, and does not maintain, a compensation committee. I. Jon Brumley, our general partner’s chairman of the board of directors, serves as the chairman of the board of EAC, and Jon S. Brumley, our general partner’s Chief Executive Officer and President and member of our general partner’s board of directors, serves as the Chief Executive Officer and President and member of the Board of Directors of EAC. However, all compensation decisions with respect to each of these persons are made by EAC and, other than with respect to the previously issued management incentive units, none of these individuals receive any compensation directly from us or our general partner. Please read “Certain Relationships and Related Transactions, and Director Independence” below for information about relationships among us, our general partner and EAC.

Compensation of Directors

Officers or employees of our general partner or its affiliates who also serve as directors do not receive additional compensation for their service as a director of our general partner. Each director is fully indemnified by us for actions associated with being a director to the extent permitted under Delaware law.

The following table sets forth a summary of the compensation paid to non-employee directors of our general partner during 2007. We were formed in February 2007, but the board of directors of our general

125

ENCORE ENERGY PARTNERS LP

partner did not include any non-management directors until August 2007. Accordingly, the compensation set forth below is for the period from August 13, 2007 through December 31, 2007.

	Fees Earned
	or Paid in		Unit
Name	Cash(a)		Awards(b)		Total(c)
Arnold L. Chavkin	$	68,000	$	100,800	$	165,800
John E. Jackson(d)		—		—		—
J. Luther King, Jr.		63,000		100,800		161,800
Clayton E. Melton		64,000		100,800		161,800
George W. Passela		73,000		100,800		170,800

(a)	Directors receive an annual retainer of $50,000 plus additional fees of $2,000 for attendance at each board meeting and $1,000 for attendance at each committee meeting. The chair of each committee receives an additional annual fee of $10,000.
(b)	Directors receive an annual grant of 5,000 phantom units under the Encore Energy Partners GP LLC Long-Term Incentive Plan. The value of the phantom unit grant is based on the closing price of our common units on October 29, 2007, the date of grant ($20.16). Phantom units vest in four equal annual installments on October 29, 2008, 2009, 2010, and 2011, subject to earlier vesting in the event of a change in control, death or disability and to such other terms as are set forth in the award agreement. Each phantom unit is accompanied by a distribution equivalent right, which entitles the holder to receive cash equal to the amount of any cash distributions made by us with respect to a common unit during the period the right is outstanding.
(c)	We also reimburse directors for out-of-pocket expenses attendant to membership on the board of directors of our general partner.
(d)	Mr. Jackson did not join the board of directors of our general partner until February 2008.

Long-Term Incentive Plan

Our general partner adopted the Encore Energy Partners GP LLC Long-Term Incentive Plan for employees, consultants, and directors of EAC, our general partner, and any of their affiliates who perform services for us. The long-term incentive plan consists of the following components: options, restricted units, phantom units, unit appreciation rights, distribution equivalent rights, other unit-based awards, and unit awards. The purpose of awards under the long-term incentive plan is to provide additional incentive compensation to employees providing services to us, and to align the economic interests of such employees with the interests of our unitholders. The long-term incentive plan limits the number of units that may be delivered pursuant to awards to 1,150,000. Common units cancelled, forfeited, or withheld to satisfy exercise prices or tax withholding obligations are available for delivery pursuant to other awards. The plan is administered by the board of directors of our general partner, or a committee thereof, which we refer to as the plan administrator.

The plan administrator may terminate or amend the long-term incentive plan at any time with respect to any units for which a grant has not yet been made. The plan administrator also has the right to alter or amend the long-term incentive plan or any part of the plan from time to time, including increasing the number of units that may be granted subject to the requirements of the exchange upon which the common units are listed at that time. However, no change in any outstanding grant may be made that would materially reduce the rights or benefits of the participant without the consent of the participant. The plan will expire on the earliest of (1) the date the units are no longer available under the plan for grants, (2) termination of the plan by the plan administrator, or (3) the date 10 years following the date of adoption.

Restricted Units.  A restricted unit is a common unit that vests over a six-month period of time and during that time is subject to forfeiture. The plan administrator may make grants of restricted units containing such terms as it shall determine, including the period over which restricted units will vest. The plan

126

ENCORE ENERGY PARTNERS LP

administrator, in its discretion, may base its determination upon the achievement of specified financial or other performance objectives. Restricted units will be entitled to receive quarterly distributions during the vesting period.

Phantom Units.  A phantom unit entitles the grantee to receive a common unit upon the vesting of the phantom unit or, in the discretion of the plan administrator, cash equivalent to the value of a common unit. The plan administrator may make grants of phantom units under the plan containing such terms as the plan administrator shall determine, including the period over which phantom units granted will vest. The plan administrator, in its discretion, may base its determination upon the achievement of specified financial objectives.

Unit Options.  The long-term incentive plan permits the grant of options covering common units. The plan administrator may make grants containing such terms as the plan administrator shall determine. Unit options must have an exercise price that is not less than the fair market value of the common units on the date of grant. In general, unit options granted will become exercisable over a period determined by the plan administrator.

Unit Appreciation Rights.  The long-term incentive plan permits the grant of unit appreciation rights. A unit appreciation right is an award that, upon exercise, entitles the participant to receive the excess of the fair market value of a common unit on the exercise date over the exercise price established for the unit appreciation right. Such excess will be paid in cash or common units. The plan administrator may make grants of unit appreciation rights containing such terms as the plan administrator shall determine. Unit appreciation rights must have an exercise price that is not less than the fair market value of the common units on the date of grant. In general, unit appreciation rights granted will become exercisable over a period determined by the plan administrator.

Distribution Equivalent Rights.  The plan administrator may, in its discretion, grant distribution equivalent rights (“DERs”) as a stand-alone award or with respect to phantom unit awards or other awards under the long-term incentive plan. DERs entitle the participant to receive cash or additional awards equal to the amount of any cash distributions made by us with respect to a common unit during the period the right is outstanding. Payment of a DER issued in connection with another award may be subject to the same vesting terms as the award to which it relates or different vesting terms, in the discretion of the plan administrator.

Other Unit-Based Awards.  The long-term incentive plan permits the grant of other unit-based awards, which are awards that are based, in whole or in part, on the value or performance of a common unit. Upon vesting, the award may be paid in common units, cash, or a combination thereof, as provided in the grant agreement.

Unit Awards.  The long-term incentive plan permits the grant of common units that are not subject to vesting restrictions. Unit awards may be in lieu of or in addition to other compensation payable to the individual.

Change in Control; Termination of Service.  Awards under the long-term incentive plan will vest and/or become exercisable, as applicable, upon a “change in control” of us or our general partner or upon a “Change of Control” as defined in EAC’s 2000 Incentive Stock Plan, unless provided otherwise by the plan administrator. The consequences of the termination of a grantee’s employment, consulting arrangement, or membership on the board of directors will be determined by the plan administrator in the terms of the relevant award agreement.

A “change in control” of us or our general partner under the long-term incentive plan includes the occurrence of one or more of the following events:

•  any person or group, other than EAC or its affiliates, becomes the beneficial owner of 50 percent or more of us or our general partner;

•  approval by our limited partners of the complete liquidation of us;

127

ENCORE ENERGY PARTNERS LP

•  the sale or other disposition of all or substantially all of our assets, other than to our general partner or its affiliates;

•  a transaction resulting in someone other than our general partner or one of its affiliates becoming our general partner; or

•  a transaction resulting in our general partner ceasing to be an affiliate of EAC.

A “Change in Control” is defined in EAC’s 2000 Incentive Stock Plan as the occurrence of one or more of the following events:

•  any person or group acquires beneficial ownership of 40 percent or more of EAC, other than through any acquisition (1) directly from EAC, (2) by EAC and its affiliates, (3) by any employee benefit plan sponsored or maintained by EAC or any corporation controlled by EAC, (4) by a corporation pursuant to a permitted transaction described in the third bullet below, or (5) by a person or group that owned on the adoption date of EAC’s 2000 Incentive Stock Plan more than 20 percent of EAC’s outstanding capital stock;

•  EAC’s incumbent board members, as of the effective date of EAC’s 2000 Incentive Stock Plan, cease to constitute at least a majority of EAC’s board of directors, provided that, any subsequent director whose election or nomination was approved by a majority vote of the directors then comprising EAC’s incumbent board members will generally be considered an EAC incumbent board member;

•  approval by EAC’s stockholders of a reorganization, merger, share exchange, or consolidation, unless, in each case following the transaction, (1) all or substantially all of EAC’s beneficial owners immediately prior to such transaction beneficially own more than 60 percent of the corporation resulting from such transaction in substantially the same proportions as their ownership immediately prior to such transaction, (2) no person or group beneficially owns 40 percent or more of the corporation resulting from such transaction except to the extent that such person or group beneficially owned 40 percent or more of EAC prior to the transaction, and (3) at least a majority of the board members of the corporation resulting from such transaction where EAC incumbent board members at the time of the execution of the initial agreement, or of the action of EAC’s board of directors, providing for such transaction; or

•  approval by EAC’s stockholders of a complete liquidation or dissolution of EAC or sale or other disposition of all or substantially all of EAC’s assets, other than to a corporation with respect to which, following such sale or other disposition, (1) more than 60 percent of such corporation is then beneficially owned by all or substantially all of the persons or groups who were the beneficial owners of EAC immediately prior to such sale or other disposition in substantially the same proportion as their ownership immediately prior to such sale or other disposition, (2) less than 40 percent of such corporation is then beneficially owned by any person or group, except to the extent that such person or group owned 40 percent or more of EAC prior to the sale or disposition, and (3) at least a majority of the board members of such corporation were EAC’s incumbent board members at the time of the execution of the initial agreement, or of the action of EAC’s board of directors, providing for such sale or other disposition or were elected, appointed, or nominated by EAC’s board of directors.

Source of Units.  Common units to be delivered pursuant to awards under the long-term incentive plan may be common units acquired by our general partner in the open market, from any other person, directly from us, or any combination of the foregoing. If we issue new common units upon the grant, vesting or payment of awards under the long-term incentive plan, the total number of common units outstanding will increase.

128

ENCORE ENERGY PARTNERS LP

ITEM 12.   SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS

The following table sets forth the beneficial ownership of our units as of February 20, 2008 by:

•  each person known by us to beneficially own 5 percent or more of our outstanding units;

•  each member of the board of directors of our general partner;

•  each named executive officer of our general partner; and

•  all directors and executive officers of our general partner as a group.

Unless otherwise noted, the persons named below have sole voting power and investment power with respect to such units.

								Percentage of
			Percentage of			Management		Management			Percentage of Total
	Common Units		Common Units			Incentive Units		Incentive Units			Units Beneficially
Name of Beneficial Owner(a)	Beneficially Owned		Beneficially Owned			Beneficially Owned		Beneficially Owned			Owned
Encore Acquisition Company(b)		20,924,055		67.3	%		—		—			66.2	%
Encore Partners LP Holdings LLC(b)		9,995,801		32.2	%		—		—			31.6	%
Encore Operating, L.P.(b)		10,928,254		35.2	%		—		—			34.6	%
I. Jon Brumley(c)		88,061		*			143,000		26	%		*
Jon S. Brumley		7,100		*			143,000		26	%		*
Robert C. Reeves		3,500		*			110,000		20	%		*
L. Ben Nivens		2,000		*			77,000		14	%		*
John W. Arms		14,200		*			77,000		14	%		*
Arnold L. Chavkin		—		*			—		—			*
John E. Jackson		—		*								*
J. Luther King, Jr.		30,000		*			—		—			*
Clayton E. Melton		2,400		*			—		—			*
George W. Passela		10,000		*			—		—			*
All executive officers and directors as a group (15 persons)		162,561		*			550,000		100	%		2.3	%

*	Less than 1%
(a)	The address for all beneficial owners in this table is 777 Main Street, Suite 1400, Fort Worth, Texas 76102.
(b)	EAC is the ultimate parent company of Encore Energy Partners LP Holdings LLC and Encore Operating, L.P. and therefore, may be deemed to beneficially own the units held by Encore Partners LP Holdings LLC and Encore Operating, L.P.
(c)	Mr. Brumley is the sole officer, director and shareholder of a corporation that is the sole general partner of a limited partnership that owns the common units. Accordingly, Mr. Brumley has sole voting and dispositive power

129

ENCORE ENERGY PARTNERS LP

with respect to the common units owned by the partnership.

The following table sets forth, as of February 20, 2008, the number of shares of common stock of EAC owned by each of the executive officers and directors of our general partner and all executive officers and directors of our general partner as a group.

	Shares of Common
	Stock Owned
	Directly or
Name of Beneficial Owner	Indirectly(a)		Percent of Class
I. Jon Brumley(b)		3,352,021		6.3	%
Jon S. Brumley		979,857		1.8	%
Robert C. Reeves		163,929			*
L. Ben Nivens		52,173			*
John W. Arms		108,546			*
Arnold L. Chavkin		—			*
John E. Jackson		400			*
J. Luther King, Jr.(c)		356,345			*
Clayton E. Melton		—			*
George W. Passela		—			*
All executive officers and directors as a group (15 persons)		5,303,227		9.9	%

*	Less than 1%
(a)	Includes options that are or become exercisable within 60 days of February 20, 2008 as follows: Mr. I. Jon Brumley (328,362), Mr. Jon S. Brumley (327,452), Mr. Reeves (98,991), Mr. Nivens (10,031), and Mr. Arms (47,073), and all executive officers and directors as a group (952,397) upon the exercise of stock options granted pursuant to EAC’s 2000 Incentive Stock Plan. Includes unvested restricted stock as of February 20, 2008 as follows: Mr. I. Jon Brumley (137,816), Mr. Jon S. Brumley (72,356), Mr. Reeves (19,994), Mr. Nivens (13,671), and Mr. Arms (15,624), and all directors and executive officers as a group (319,008). With respect to Mr. Jon S. Brumley, includes 448,952 shares pledged as collateral pursuant to customary brokerage arrangements.
(b)	Mr. Brumley is the sole officer, director, and shareholder of the corporation that is the sole general partner of two limited partnerships that own a total of 2,586,921 shares. Accordingly, Mr. Brumley has sole voting and dispositive power with respect to the shares owned by these partnerships.
(c)	Represents shares of EAC held by clients of Luther King Capital Management Corporation (“LKCM”), a registered investment advisory firm controlled by Mr. King. Pursuant to investment management agreements with such clients, LKCM and Mr. King have voting power and investment power over such shares. Mr. King disclaims beneficial ownership of such shares, except to the extent of his pecuniary interest therein.

130

ENCORE ENERGY PARTNERS LP

The following table sets forth information about our common units that may be issued under equity compensation plans as of December 31, 2007:

	(a)		(b)		(c)
					Number of
	Number of				Units Remaining
	Units to				Available for
	be Issued		Weighted-Average Exercise		Future Issuance
	Upon Exercise		Price of		Under Equity Compensation
	of Outstanding		Outstanding Options,		Plans (Excluding
	Options, Warrants		Warrants and		Securities
	and Rights		Rights		Reflected in Column (a))
Equity compensation plans approved by unitholders		20,000		—		1,130,000
Equity compensation plans not approved by unitholders		—		—		—
Total		20,000		—		1,130,000

For discussion of our equity compensation plan, please see the discussion under “Item 11. Executive Compensation.”

ITEM 13.   CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

As of February 20, 2008, affiliates of our general partner, including directors and executive officers of our general partner, owned 21,084,955 common units representing a 66.4 percent limited partner interest in us. In addition, our general partner owned 504,851 general partner units representing a 1.6 percent general partner interest in us.

Distributions and Payments to Our General Partner and Its Affiliates

The following table summarizes the distributions and payments to be made by us to our general partner and its affiliates in connection with the ongoing operation and upon liquidation of the Partnership. These distributions and payments were determined by and among affiliated entities.

Ongoing Operations of the Partnership

Distributions of available cash to our general partner and its affiliates

We make cash distributions to our unitholders, including our general partner and its affiliates, as the holders of 20,924,055 common units, 550,000 management incentive units, and 504,851 general partner units. In distributing available cash, we will assume 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 will be subject to a maximum limit equal to 5.1 percent of all such distributions to all unitholders at the time of any such distribution. If the 5.1 percent maximum limit on aggregate distributions to the holders of our management incentive units is reached, then any available cash that would have been distributed to such holders will be available for distribution to our unitholders.

Payments to our general partner and its affiliates

Our partnership agreement requires us to reimburse our general partner for all actual direct and indirect expenses it incurs or actual payments it makes on our behalf and all other expenses allocable

131

ENCORE ENERGY PARTNERS LP

to us or otherwise incurred by our general partner in connection with operating our business. We do not expect to incur any additional fees or to make other payments to our general partner in connection with operating our business. Our amended and restated administrative services agreement requires us to pay Encore Operating, L.P. an administrative fee of $1.75 per BOE of our production for general and administrative services and reimburse Encore Operating, L.P. for actual third-party expenses incurred on our behalf. Encore Operating, L.P. 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 agreements. In addition, Encore Operating, L.P. 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. For further information regarding the amended and restated administrative services agreement, see “Amended and Restated Administrative Services Agreement” below.

Withdrawal or removal of our general partner

If our general partner withdraws or is removed, its general partner interest will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests.

Upon Liquidation of the Partnership

Liquidation Upon our liquidation, the partners, including our general partner, will be entitled to receive liquidating distributions according to their respective capital account balances.

Contribution, Conveyance and Assumption Agreement

During 2007, we entered into a contribution, conveyance and assumption agreement (the “Permian Basin Contribution Agreement”) with our general partner, OLLC, Encore Operating, EAC, and Encore Partners LP Holdings LLC. The following transactions, among others, occurred pursuant to the Permian Basin Contribution Agreement:

•  Encore Operating transferred certain assets in the Permian Basin of West Texas to us in exchange for 4,043,478 common units; and

•  EAC agreed to indemnify us 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.

Under the Permian Basin Contribution Agreement, EAC agreed to indemnify us for one year after the closing of the initial public offering against certain potential environmental claims, losses and expenses associated with the operation of the assets and occurring before the closing date of the initial public offering. EAC’s maximum liability for the indemnification obligation will not exceed $10 million. EAC does not have any obligation under this indemnification obligation until our aggregate losses exceed $500,000, and then only to the extent such aggregate losses exceed $500,000. EAC does not have any indemnification obligations with respect to environmental matters for claims made as a result of changes in environmental laws promulgated after the closing of the initial public offering.

Additionally, EAC agreed to indemnify us for losses attributable to title defects related to the Permian Basin assets for three years after the closing of the initial public offering, indefinitely for losses attributable to

132

ENCORE ENERGY PARTNERS LP

retained assets and liabilities and until the expiration of the applicable statutes of limitations for income taxes attributable to pre-closing operations of the Permian Basin assets. Furthermore, we will indemnify EAC for all losses attributable to the post-closing operations of the assets contributed to us, to the extent not subject to their indemnification obligations.

Purchase and Investment Agreement

On December 27, 2007, we entered into a purchase and investment agreement (the “Purchase Agreement”) with Encore Operating. The Purchase Agreement provided for the acquisition of certain oil and natural gas producing properties and related assets in the Permian and Williston Basins from Encore Operating. The transaction closed on February 7, 2008 and was effective January 1, 2008.

The consideration for the acquisition consisted of $125.4 million in cash and 6,884,776 common units representing limited partner interests in us. We financed the cash portion of the purchase price through additional borrowings under our revolving credit facility. After the transaction, EAC and its affiliates, including Encore Operating, own 20,924,055 of our outstanding common units, or approximately 67 percent. EAC, through its indirect ownership of our general partner, also holds 504,851 general partner units.

Amended and Restated Administrative Services Agreement

We entered into an amended and restated administrative service agreement with Encore Operating pursuant to which Encore Operating performs administrative services for us, such as accounting, corporate development, finance, land, legal, and engineering. Encore Operating provides all personnel and any facilities, goods, and equipment necessary to perform these services and not otherwise provided by us. Encore Operating receives 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 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. COPAS is 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. Most joint operating agreements provide for an annual increase or decrease in the COPAS overhead rate for drilling and producing wells. The rate change, which occurs in April, is based on the change in average weekly earnings as measured by an index published by the United States Department of Labor, Bureau of Labor Statistics. The COPAS overhead cost is charged to all non-operating interest owners under a joint operating agreement each month.

We will also reimburse EAC for any additional state income, franchise or similar tax paid by EAC resulting from the inclusion of us (and our subsidiaries) in a combined state income, franchise, or similar tax report with EAC as required by applicable law. The amount of any such reimbursement will be limited to the tax that we (and our subsidiaries) would have paid had we not been included in a combined group with EAC.

The administrative fee will increase in the following circumstances:

•  beginning on the first day of April in each year beginning on April 1, 2008 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 the general partner; or

133

ENCORE ENERGY PARTNERS LP

•  otherwise as agreed upon by Encore Operating and our general partner, with the approval of the conflicts committee of our general partner.

Encore Operating will not be liable to us for its performance of, or failure to perform, services under the Administrative Services Agreement unless its acts or omissions constitute gross negligence or willful misconduct.

The amended and restated administrative services agreement will terminate in the following circumstances:

•  at our discretion upon 90 days notice to Encore Operating;

•  at the discretion of Encore Operating upon 90 days notice to us;

•  upon a change in control of our general partner or Encore Operating by EAC or upon Encore Operating’s failure to pay an employee within 30 days of the date such employee’s payment is due, subject to certain limitations; or

•  upon the bankruptcy, dissolution, liquidation, or winding up of Encore Operating.

Subordinated Term Loan

On March 7, 2007, Encore Energy Partners Operating, LLC, our operating company, 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 us in the aggregate amount of $120 million. The subordinated term loan was repaid in full using a portion of the proceeds from our initial public offering.

Policies and Procedures for Approval of Related Person Transactions

In February 2008, the board of directors of our general partner adopted a policy with respect to related person transactions to document procedures pursuant to which such transactions are reviewed, approved or ratified. The policy applies to any transaction in which (1) we are a participant, (2) any related person has a direct or indirect material interest and (3) the amount involved exceeds $120,000, but excludes any transaction that does not require disclosure under Item 404(a) of Regulation S-K. The Nominating and Corporate Governance Committee, with assistance from our General Counsel, is responsible for reviewing, approving and ratifying any related person transaction.

Director Independence

All members of the board of directors of our general partner, other than Mr. I. Jon Brumley, Mr. Jon S. Brumley, and Mr. John E. Jackson, are independent as defined under the independence standards established by the NYSE. The NYSE does not require a listed limited partnership like us to have a majority of independent directors on the board of directors of our general partner.

134

ENCORE ENERGY PARTNERS LP

ITEM 14.   PRINCIPAL ACCOUNTING FEES AND SERVICES

The audit committee of the board of directors of our general partner selected Ernst & Young LLP as our independent registered public accounting firm to audit our consolidated financial statements for the year ended December 31, 2007.

Fees Incurred by Us for Services Provided by Ernst & Young LLP

The following table shows the fees paid or accrued by us for audit services provided by Ernst & Young LLP for the year ended December 31, 2007. There were no audit-related fees, tax fees, or other fees paid to Ernst & Young LLP for services in 2007.

Audit Fees(a)	$	1,219,317
Audit-Related Fees		—
Tax Fees		—
All Other Fees		—
Total		1,219,317

(a) Audit fees represent fees for professional services provided in connection with the annual audit of our consolidated financial statements, review of our quarterly consolidated financial statements, audits performed as part of our registration filings, and audit services provided in connection with filings with the SEC, including comfort letters and consents.

Audit Committee’s Pre-Approval Policy and Procedures

The audit committee’s policy is to pre-approve all audit and permissible non-audit services provided by the independent registered public accounting firm. These services may include audit services, audit-related services, and other services. Pre-approval is detailed as to the specific service or category of service and is subject to a specific approval. The audit committee requires the independent registered public accounting firm and management to report on the actual fees charged for each category of service at audit committee meetings throughout the year.

During the year, circumstances may arise when it may become necessary to engage the independent registered public accounting firm for additional services not contemplated in the original pre-approval. In those circumstances, the audit committee requires specific pre-approval before engaging the independent registered public accounting firm. The audit committee has delegated pre-approval authority to the chairman of the audit committee for those instances when pre-approval is needed prior to a scheduled audit committee meeting. The chairman of the audit committee must report on such approval at the next scheduled audit committee meeting.

All 2007 audit and non-audit services provided by the independent registered public accounting firm were pre-approved.

135

ENCORE ENERGY PARTNERS LP

PART IV

ITEM 15.   EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a) The following documents are filed as a part of this Report:

1. Financial Statements:

	Page
Report of Independent Registered Public Accounting Firm		78
Consolidated Balance Sheets as of December 31, 2007 and 2006		79
Consolidated Statements of Operations for the Years Ended December 31, 2007, 2006, and 2005		80
Consolidated Statements of Partners’ Equity for the Years Ended December 31, 2007, 2006, and 2005		81
Consolidated Statements of Cash Flows for the Years Ended December 31, 2007, 2006, and 2005		82
Notes to Consolidated Financial Statements		83

2. Financial Statement Schedules:

All financial statement schedules have been omitted because they are not applicable or the required information is presented in the consolidated financial statements and related notes.

(b) Exhibits

See Index to Exhibits on the following page for a description of the exhibits filed as a part of this Report.

136

ENCORE ENERGY PARTNERS LP

INDEX TO EXHIBITS

Exhibit
No.			Description
	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).
	10	.1	Credit Agreement dated as of March 7, 2007 by and among Encore Energy Partners Operating LLC, Encore Energy Partners LP, Bank of America, N.A., as administrative agent and L/C Issuer, Banc of America Securities LLC, as sole lead arranger and sole book manager, and other lenders (incorporated by reference to Exhibit 10.2 to Encore Acquisition Company’s Current Report on Form 8-K, filed with the SEC on March 13, 2007).
	10	.2	First Amendment to Credit Agreement by and among Encore Energy Partners Operating LLC, Encore Energy Partner LP, Bank of America, N.A., as administrative agent and L/C Issuer, Banc of America Securities LLC, as sole lead arranger and sole book manager, and other lenders (incorporated by reference to Exhibit 10.2 to Amendment No. 4 to Form S-1 for Encore Energy Partners LP, filed with the SEC on August 28, 2007).
	10	.3	Contribution, Conveyance and Assumption Agreement, dated as of September 17, 2007, by and among Encore Energy Partners LP, Encore Energy Partners GP LLC, Encore Acquisition Company, Encore Operating, L.P., Encore Partners GP Holdings LLC, Encore Partners LP Holdings LLC and Encore Energy Partners Operating LLC (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K, filed with the SEC on September 21, 2007).
	10	.4	Purchase and Investment Agreement dated December 27, 2007 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).
	10	.5	Amended and Restated Administrative Services Agreement, dated as of September 17, 2007, by and among Encore Energy Partners GP LLC, Encore Energy Partners LP, Encore Energy Partners Operating LLC, Encore Acquisition Company and Encore Operating, L.P. (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K, filed with the SEC on September 21, 2007).
	10	.6+	Encore Energy Partners GP LLC Long-Term Incentive Plan, dated as of September 17, 2007 (incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K, filed with the SEC on September 21, 2007).
	10	.7+	Form of Phantom Unit Award Agreement (incorporated by reference to Exhibit 10.10 to Amendment No. 3 to Form S-1 for Encore Energy Partners LP, filed with the SEC on August 10, 2007).
	12	.1*	Statement showing computation of ratio of earnings to fixed charges.
	21	.1*	Subsidiaries of Encore Energy Partners LP as of February 1, 2008.
	23	.1*	Consent of Ernst & Young LLP.
	23	.2*	Consent of Miller and Lents, Ltd.
	24	.1*	Power of Attorney (included on the signature page of this Report).
	31	.1*	Rule 13a-14(a)/15d-14(a) Certification (Principal Executive Officer of our General Partner).
	31	.2*	Rule 13a-14(a)/15d-14(a) Certification (Principal Financial Officer of our General Partner).
	32	.1*	Section 1350 Certification (Principal Executive Officer of our General Partner).
	32	.2*	Section 1350 Certification (Principal Financial Officer of our General Partner).
	99	.1*	Encore Energy Partners GP LLC Financial Statements.

*	Filed herewith
+	Management contract or compensatory plan, contract, or arrangement.

137

ENCORE ENERGY PARTNERS LP

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

ENCORE ENERGY PARTNERS LP

By: Encore Energy Partners GP LLC, its General Partner

Date: February 26, 2008 By: /s/  Jon S. Brumley
Jon S. Brumley
Chief Executive Officer and President

KNOW ALL MEN BY THESE PRESENTS, that each individual whose signature appears below constitutes and appoints Jon S. Brumley and Robert C. Reeves, and each of them, his true and lawful attorneys-in-fact and agents with full power of substitution, for him and in his name, place and stead, in any and all capacities, to sign any and all amendments (including post-effective amendments) to this report, and to file the same, with all exhibits thereto, and all documents in connection therewith, with the SEC, granting unto said attorneys-in-fact and agents, full power and authority to do and perform each and every act and thing requisite and necessary to be done in and about the premises, as fully to all intents and purposes as he might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or his or their substitutes, may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant in the capacities and on the dates indicated.

	Title or Capacity (Position with Encore
Signature	Energy Partners GP LLC)	Date
/s/  I. Jon Brumley I. Jon Brumley	Chairman of the Board and Director	February 26, 2008
/s/  Jon S. Brumley Jon S. Brumley	Chief Executive Officer, President, and Director (Principal Executive Officer)	February 26, 2008
/s/  Robert C. Reeves Robert C. Reeves	Senior Vice President, Chief Financial Officer, and Treasurer (Principal Financial Officer)	February 26, 2008
/s/  Andrea Hunter Andrea Hunter	Vice President, Controller, and Principal Accounting Officer	February 26, 2008
/s/  Arnold L. Chavkin Arnold L. Chavkin	Director	February 26, 2008
/s/  John E. Jackson John E. Jackson	Director	February 26, 2008

138

ENCORE ENERGY PARTNERS LP

	Title or Capacity (Position with Encore
Signature	Energy Partners GP LLC)	Date
/s/  J. Luther King, Jr. J. Luther King, Jr.	Director	February 26, 2008
/s/  Clayton E. Melton Clayton E. Melton	Director	February 26, 2008
/s/  George W. Passela George W. Passela	Director	February 26, 2008

139

EX-12.1

Exhibit 12.1

ENCORE ENERGY PARTNERS LP

RATIO OF EARNINGS TO FIXED CHARGES
(in thousands, except ratios)

	Three months ended December 31,					Year ended December 31,
	2007			2006		2007			2006
Income (loss) before income taxes	$	(11,216	)	$	1,438	$	(25,343	)	$	7,770
Adjustments:
Add fixed charges:
Interest expense		1,021			—		12,294			—
Rental expense attributable to interest		7			6		31			23
Total fixed charges		1,028			6		12,325			23
Adjusted earnings	$	(10,188	)	$	1,444	$	(13,018	)	$	7,793
Ratio of earnings to fixed charges		(9.9	)		240.7		(1.1	)		338.8

(a) For the three months and year ended December 31, 2007, earnings as defined were inadequate to cover fixed charges as defined by $11.2 million and $25.3 million, respectively.

EX-21.1

Exhibit 21.1

Subsidiaries of Encore Energy Partners LP as of February 1, 2008

	State or other Jurisdiction of
Name of Subsidiary	Incorporation or Organization
Encore Energy Partners Operating LLC	Delaware
Encore Clear Fork Pipeline LLC	Delaware

EX-23.1

Exhibit 23.1

Consent of Independent Registered Public Accounting Firm

We consent to the incorporation by reference in the Registration Statement on Form S-8 (File No. 333-147004) pertaining to the Encore Energy Partners GP LLC Long-Term Incentive Plan of our reports dated February 27, 2008, with respect to the consolidated financial statements of Encore Energy Partners LP and the consolidated balance sheet of Encore Energy Partners GP LLC, included in this Annual Report (Form 10-K) for the year ended December 31, 2007.

/s/ Ernst & Young LLP

Fort Worth, Texas
February 27, 2008

EX-23.2

Exhibit 23.2

Consent of Independent Petroleum Engineers

     The firm of Miller and Lents, Ltd. hereby consents to the use of its name and to the reference to its report dated January 16, 2008 regarding Encore Energy Partners LP’s Proved Reserves and Future Net Revenues as of December 31, 2007, in Encore Energy Partners LP’s annual report for the year ended December 31, 2007 filed on Form 10-K with the Securities and Exchange Commission.

MILLER AND LENTS, LTD.

By: /s/ Carl D. Richard Carl D. Richard

Senior Vice President

Houston, Texas
February 25, 2008

EX-31.1

Exhibit 31.1

Rule 13a-14(a)/15d-14(a) Certification

I, Jon S. Brumley, certify that:

1.	I have reviewed this annual report on Form 10-K of Encore Energy Partners LP;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b)	[Omitted pursuant to SEC Release No. 33-8238; 34-47986]
(c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 26, 2008	/s/ Jon S. Brumley
	Jon S. Brumley
	Chief Executive Officer and President of Encore Energy Partners GP LLC, the General Partner of Encore Energy Partners LP

EX-31.2

Exhibit 31.2

Rule 13a-14(a)/15d-14(a) Certification

I, Robert C. Reeves, certify that:

1.	I have reviewed this annual report on Form 10-K of Encore Energy Partners LP;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b)	[Omitted pursuant to SEC Release No. 33-8238; 34-47986]
(c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 26, 2008	/s/ Robert C. Reeves
	Robert C. Reeves
	Senior Vice President, Chief Financial Officer, and Treasurer
	of Encore Energy Partners GP LLC, the General Partner of
	Encore Energy Partners LP

EX-32.1

Exhibit 32.1

Section 1350 Certification

     In connection with the Annual Report of Encore Energy Partners LP (the “Partnership”) on Form 10-K for the year ended December 31, 2007 as filed with the Securities and Exchange Commission (the “SEC”) on the date hereof (the “Report”), I, Jon S. Brumley, Chief Executive Officer of Encore Energy Partners GP LLC, the General Partner of the Partnership, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

Date: February 26, 2008	/s/ Jon S. Brumley
	Jon S. Brumley
	Chief Executive Officer and President of Encore Energy
	Partners GP LLC, the General Partner of Encore Energy
	Partners LP

     A signed original of this written statement required by Section 906 has been provided to the Partnership and will be retained by the Partnership and furnished to the SEC or its staff upon request.

Note: The certification of the registrant furnished in this exhibit is not deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liabilities of that Section. Registration statements or other documents filed with the SEC shall not incorporate this exhibit by reference, except as otherwise expressly stated in such filing.

EX-32.2

Exhibit 32.2

Section 1350 Certification

     In connection with the Annual Report of Encore Energy Partners LP (the “Partnership”) on Form 10-K for the year ended December 31, 2007 as filed with the Securities and Exchange Commission (the “SEC”) on the date hereof (the “Report”), I, Robert C. Reeves, Chief Financial Officer of Encore Energy Partners GP LLC, the General Partner of the Partnership, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

Date: February 26, 2008	/s/ Robert C. Reeves
	Robert C. Reeves
	Senior Vice President, Chief Financial Officer, and Treasurer
	of Encore Energy Partners GP LLC, the General Partner of
	Encore Energy Partners LP

     A signed original of this written statement required by Section 906 has been provided to the Partnership and will be retained by the Partnership and furnished to the SEC or its staff upon request.

Note: The certification of the registrant furnished in this exhibit is not deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liabilities of that Section. Registration statements or other documents filed with the SEC shall not incorporate this exhibit by reference, except as otherwise expressly stated in such filing.

EX-99.1

Exhibit 99.1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of Encore Energy Partners GP LLC:

     We have audited the accompanying consolidated balance sheet of Encore Energy Partners GP LLC (the “Company”) as of December 31, 2007. This balance sheet is the responsibility of the Company’s management. Our responsibility is to express an opinion on this balance sheet based on our audit.

     We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the balance sheet is free of material misstatement. We were not engaged to perform an audit of the Company’s internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the balance sheet, assessing the accounting principles used and significant estimates made by management, and evaluating the overall balance sheet presentation. We believe that our audit of the balance sheet provides a reasonable basis for our opinion.

     In our opinion, the consolidated balance sheet referred to above presents fairly, in all material respects, the consolidated financial position of Encore Energy Partners GP LLC at December 31, 2007, in conformity with U.S. generally accepted accounting principles.

     As discussed in Note 2 to the consolidated balance sheet, on January 1, 2007, the Company adopted Financial Accounting Standards Board Interpretation No. 48, “Accounting for Uncertainty in Income Taxes — an Interpretation of FASB Statement No. 109.”

/s/ Ernst & Young LLP

Fort Worth, Texas
February 27, 2008

ENCORE ENERGY PARTNERS GP LLC

CONSOLIDATED BALANCE SHEET
December 31, 2007
(in thousands)

ASSETS
Current assets:
Cash and cash equivalents	$	3
Accounts receivable:
Trade		16,239
Affiliate		653
Derivatives		3,713
Prepaid expenses and other		448
Total current assets		21,056
Properties and equipment, at cost — successful efforts method:
Proved properties, including wells and related equipment		378,170
Accumulated depletion, depreciation, and amortization		(37,661	)
		340,509
Other property and equipment		457
Accumulated depreciation		(50	)
		407
Intangibles, net		3,969
Derivatives		21,875
Debt issuance costs, net		1,451
Other		812
Total assets	$	390,079
LIABILITIES AND OWNER’S NET EQUITY
Current liabilities:
Accounts payable:
Trade	$	1,915
Affiliate		1,326
Accrued liabilities:
Lease operations expense		1,905
Development capital		2,249
Interest		147
Production, ad valorem, and severance taxes		5,448
Natural gas purchases		1,578
Derivatives		865
Other		2,452
Total current liabilities		17,885
Derivatives		20,447
Future abandonment cost		6,068
Long-term debt		47,500
Other		16
Total liabilities		91,916
Commitments and contingencies (see Note 4)		—
Minority interest		122,534
Owner’s net equity:
Owner’s net equity		175,629
Total owner’s net equity		175,629
Total liabilities and owner’s net equity	$	390,079

The accompanying notes are an integral part of this consolidated balance sheet.

1

ENCORE ENERGY PARTNERS GP LLC

NOTES TO CONSOLIDATED BALANCE SHEET

Note 1. Formation of the Company and Description of Business

     Encore Energy Partners GP LLC, a Delaware limited liability company (the “Company” or the “General Partner”), was formed on February 13, 2007, to own a 2 percent general partner interest in Encore Energy Partners LP, a Delaware limited partnership (“ENP” or the “Partnership”). The General Partner is a wholly owned subsidiary of Encore Partners GP Holdings LLC, a Delaware limited liability company (“GP Holdings”). GP Holdings is a wholly owned subsidiary of Encore Acquisition Company, a publicly traded Delaware corporation (“EAC”). As of December 31, 2007, EAC also owned 58 percent of the Partnership’s outstanding common units.

     The General Partner is deemed to control the Partnership because, under Delaware laws and the partnership agreement, the General Partner has the power to direct or cause the direction of the management and policies of the Partnership. As a result of this substantive control, the Partnership is fully consolidated and therefore, the consolidated balance sheet includes all assets and liabilities of the Partnership and its subsidiaries. The General Partner does not own an interest in any other companies.

     The Partnership was 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. Also in February 2007, 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 oil and natural gas properties and related assets in the Elk Basin of Wyoming and Montana (the “Elk Basin Assets”), which the Partnership acquired in March 2007 from certain subsidiaries of Anadarko Petroleum Corporation (“Anadarko”), 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”), and oil and natural gas properties and related assets in the Permian Basin of West Texas and Williston Basin of North Dakota, acquired from Encore Operating, L.P. (“Encore Operating”), a wholly owned subsidiary of EAC, in February 2008. See “Note 3. Acquisition” for additional discussion of the acquisition of the Elk Basin Assets. See “Note 11. Subsequent Events” for details regarding the Partnership's February 2008 acquisition of the Permian and Williston Basin properties from Encore Operating. Prior to the closing of the IPO, EAC owned all the general and limited partner interests in the Partnership, with the exception of management incentive units owned by certain executive officers of the General Partner. See “Note 8. Unit-Based Compensation Plans” for additional discussion of the management incentive units.

Initial Public Offering and Concurrent Transactions

     On September 17, 2007, the Partnership completed its IPO of 9,000,000 common units at a price to the public of $21.00 per unit. The net proceeds of $171.0 million, after deducting the underwriters’ discount and a structuring fee of $13.2 million, in the aggregate, and offering expenses of $4.7 million, were used to repay in full the $126.4 million of outstanding indebtedness under the Partnership’s subordinated credit agreement and $43.5 million of outstanding borrowings under OLLC’s revolving credit facility. See “Note 6. Debt” for additional discussion of the Partnership’s long-term debt.

     On October 11, 2007, the underwriters exercised their over-allotment option to purchase an additional 1,148,400 common units, which closed on October 16, 2007. The net proceeds of $22.4 million, after deducting the underwriters’ discount and a structuring fee of $1.7 million, were used to repay outstanding borrowings under OLLC’s revolving credit facility. After completion of the IPO and the underwriters’ over-allotment exercise, 42 percent of the Partnership’s common units were publicly held.

     At the closing of the IPO on September 17, 2007, 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, 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.

2

ENCORE ENERGY PARTNERS GP LLC

NOTES TO CONSOLIDATED BALANCE SHEET — (Continued)

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 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. 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 receives an administrative fee of $1.75 per BOE of the Partnership’s production for such services and reimbursement of actual third-party expenses incurred 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.
	The Partnership reimburses EAC for any additional state income, franchise, or similar tax paid by EAC resulting from the inclusion of the Partnership (and its subsidiaries) in a combined state income, franchise, or similar tax report with EAC as required by applicable law. The amount of any such reimbursement will be limited to the tax that the Partnership (and its subsidiaries) would have paid had it not been included in a combined group with EAC. See “Note 10. 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, 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 8. Unit-Based Compensation Plans” for additional discussion regarding the ENP Incentive Plan.

Note 2. Summary of Significant Accounting Policies

Basis of Presentation

     In accordance with Emerging Issues Task Force Issue No. 04-5, “Determining Whether a General Partner, or the General Partners as a Group, Controls a Limited Partnership or Similar Entity When the Limited Partners Have Certain Rights,” the General Partner consolidates the Partnership in its financial statements. The Company’s consolidated balance sheet includes the accounts of the General Partner and the Partnership, its controlled subsidiary. The public unitholders’ interest is reflected as “Minority interest” in the accompany Consolidated Balance Sheet. The Company elected to account for gains on ENP’s issuance of common units as capital transactions as permitted by Staff Accounting Bulletin Topic 5H, “Accounting for Sales of Stock by a Subsidiary.” During 2007, the Company reclassified $77.6 million from “Minority interest” to “Owner’s net equity” on the accompanying Consolidated Balance Sheet to recognize the gain on sale of ENP’s common units in 2007. All material intercompany balances and transactions have been eliminated in consolidation.

     The Permian 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. The contribution of the Permian Basin Assets by EAC was accounted for as a transaction between entities under common control. Therefore, the assets and liabilities of the Permian Basin Assets were recorded on the Partnership’s balance sheet at EAC’s historical basis.

Use of Estimates

     Preparing financial statements in conformity with accounting principles generally accepted in the United States requires management to make certain estimations and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities in the consolidated balance sheet. Actual results could differ materially from those estimates.

     Estimates made in preparing this consolidated balance sheet include, among other things, estimates of the proved oil and natural gas reserve volumes used in calculating depletion, depreciation, and amortization (“DD&A”) expense; the estimated future cash flows and fair value of properties used in determining the need for any impairment write-down; operating costs accrued; volumes and prices for revenues accrued; and the timing and amount of future abandonment costs used in calculating asset retirement obligations. Future changes in the assumptions used could have a significant impact on reported results in future periods.

3

ENCORE ENERGY PARTNERS GP LLC

NOTES TO CONSOLIDATED BALANCE SHEET — (Continued)

Cash and Cash Equivalents

     Cash and cash equivalents include cash in banks, money market accounts, and all highly liquid investments with an original maturity of three months or less.

Accounts Receivable

     The Company’s trade accounts receivable, which are primarily from oil and natural gas sales do not bear interest and are recorded at the invoiced amount. The Company routinely reviews outstanding accounts receivable balances and assesses the financial strength of its customers. A reserve is recorded for amounts it expects will not be fully recovered. Actual balances are not applied against the reserve until substantially all collection efforts have been exhausted. At December 31, 2007 and 2006, the Company did not have any allowance for doubtful accounts.

Properties and Equipment

     Oil and Natural Gas Properties. The Company adheres to Statement of Financial Accounting Standards (“SFAS”) No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies” (“SFAS 19”), utilizing the successful efforts method of accounting for its oil and natural gas properties. Under this method, all costs associated with productive and nonproductive development wells are capitalized. Costs associated with drilling exploratory wells are initially capitalized pending determination of whether the well is economically productive or nonproductive.

     If an exploratory well does not find reserves or does not find reserves in a sufficient quantity as to make them economically producible, the previously capitalized costs are expensed in the period in which the determination was made. If an exploratory well finds reserves but they cannot be classified as proved, the Company continues to capitalize the associated cost as long as the well has found a sufficient quantity of reserves to justify its completion as a producing well and sufficient progress is being made in assessing the reserves and the operating viability of the project. If subsequently it is determined that neither of these conditions continues to exist, all previously capitalized costs associated with the exploratory well are expensed. Re-drilling or directional drilling in a previously abandoned well is classified as development or exploratory based on whether it is in a proved or unproved reservoir. Expenditures to recomplete a current well in a different unproved reservoir are capitalized pending determination that economic reserves have been added. If the recompletion is not successful, the expenditures are charged to expense. The Company did not drill any exploratory wells during 2007.

     Significant tangible equipment added or replaced is capitalized. Expenditures to construct facilities or increase the productive capacity from existing reservoirs are capitalized. Capitalized costs are amortized on a unit-of-production basis over the remaining life of proved developed reserves or total proved reserves, as applicable. Natural gas volumes are converted to barrels of oil equivalent (“BOE”) at the rate of six thousand cubic feet (“Mcf”) of natural gas to one barrel (“Bbl”) of oil.

     The costs of retired, sold, or abandoned properties that constitute part of an amortization base are charged or credited, net of proceeds received, to the accumulated DD&A reserve. Gains or losses from the disposal of other properties are recognized in the current period.

     Miller and Lents, Ltd., independent reserve engineers, estimates the Company’s reserves annually on December 31. This results in a new DD&A rate which the Company uses for the preceding fourth quarter after adjusting for fourth quarter production. The Company internally estimates reserve additions and reclassifications of reserves from proved undeveloped to proved developed at the end of the first, second, and third quarters for use in determining a DD&A rate for the quarter.

     In accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” (“SFAS 144”) the Company is required to assess the need for an impairment of capitalized costs of long-lived assets to be held and used, including proved oil and natural gas properties, whenever events and circumstances indicate that the carrying value of the asset may not be recoverable. If impairment is indicated based on a comparison of the asset’s carrying value to its undiscounted expected future net cash flows, then it is recognized to the extent that the carrying value exceeds fair value. Expected future net cash flows are based on existing proved reserve and production information and pricing assumptions that management believes are representative of future economics. Any impairment charge incurred is expensed and reduces the recorded basis in the asset.

     Unproved properties, the majority of the costs of which relate to the acquisition of leasehold interests, are assessed for

4

ENCORE ENERGY PARTNERS GP LLC

NOTES TO CONSOLIDATED BALANCE SHEET — (Continued)

impairment on a property-by-property basis for individually significant balances and on an aggregate basis for individually insignificant balances. If the assessment indicates an impairment, a loss is recognized by providing a valuation allowance at the level consistent with the level at which impairment was assessed. The impairment assessment is affected by economic factors such as the results of exploration activities, commodity price outlooks, remaining lease terms, and potential shifts in business strategy employed by management. In the case of individually insignificant balances, the amount of the impairment loss recognized is determined by amortizing the portion of these properties’ costs which ENP believes will not be transferred to proved over the average life of the lease. The Company did not hold any unproved properties during 2007.

     Amounts shown in the accompanying Consolidated Balance Sheet as “Proved properties” include leasehold costs and wells and related equipment, both completed and in process, and consisted of the following as of December 31, 2007 (in thousands):

Proved leasehold costs	$	297,777
Wells and related equipment — Completed		77,143
Wells and related equipment — In process		3,250
Total proved properties	$	378,170

     Other Property and Equipment. Other property and equipment is carried at cost. Depreciation is expensed on a straight-line basis over estimated useful lives, which range from three to seven years.

Intangible Assets

     The Company accounts for intangible assets under the provisions of SFAS No. 142, “Goodwill and Other Intangible Assets.” Intangible assets with definite useful lives are amortized over their estimated useful lives. In accordance with SFAS 144, the Company evaluates the recoverability of intangible assets with definite useful lives whenever events or changes in circumstances indicate that the carrying value of the asset may not be fully recoverable. An impairment loss exists when estimated undiscounted cash flows expected to result from the use of the asset and its eventual disposition are less than its carrying amount.

     In connection with the Partnership’s acquisition of the Elk Basin Assets, the Partnership acquired a contract to purchase natural gas at a below market price for use as field fuel. The fair value of this contract, net of related amortization, is shown as “Intangibles, net” on the accompanying Consolidated Balance Sheet as of December 31, 2007. The value of this contract is amortized on a straight-line basis over its estimated useful life of approximately 14 years. As of December 31, 2007, the gross carrying amount of the contract was $4.2 million, and accumulated amortization was $0.3 million.

Asset Retirement Obligations

     SFAS No. 143, “Accounting for Asset Retirement Obligations” requires that the fair value of a liability for an asset retirement obligation (“ARO”) be recognized in the period in which the liability is incurred. For oil and natural gas properties, this is the period in which an oil or natural gas well is acquired or drilled. An amount equal to and offsetting the ARO is capitalized as part of the carrying amount of the Company’s oil and natural gas properties at its discounted fair value. The liability is then accreted each period until it is settled or the well is sold, at which time the liability is reversed. Estimates are based on historical experience in plugging and abandoning wells and estimated remaining field life based on reserve estimates. The Company does not provide for a market risk premium associated with AROs because a reliable estimate cannot be determined. See “Note 5. Asset Retirement Obligations” for additional information.

Environmental Costs

     The Company capitalizes or expenses environmental expenditures, as appropriate, depending on whether the expenditure has a future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefit are expensed. Liabilities for such expenditures are recorded on an undiscounted basis when environmental assessments or clean-ups are probable and the costs can be reliably estimated. Expenditures that extend the life of the related property or mitigate or prevent future environmental contamination are capitalized.

Unit-Based Compensation

5

ENCORE ENERGY PARTNERS GP LLC

NOTES TO CONSOLIDATED BALANCE SHEET — (Continued)

     The Company does not have any employees. However, the ENP Incentive Plan provides for the grant of unit awards and unit-based awards for employees, consultants, and directors of EAC, the General Partner, and any of their affiliates that perform services for the Partnership. In addition, in May 2007, the Company’s board of directors issued 550,000 management incentive units to certain executive officers of the General Partner.

     The Company accounts for unit-based compensation according to the provisions of SFAS No. 123 (revised 2004), “Share-Based Payment” (“SFAS 123R”). SFAS 123R requires the recognition of compensation expense, over the requisite service period, in an amount equal to the fair value of unit-based payments granted. See “Note 8. Unit-Based Compensation Plans” for additional discussion of the Company’s unit-based compensation plans.

Income Taxes

     The Company is not a taxable entity for federal and state income tax purposes. The Company is included in the consolidated return of its parent, EAC, and the tax on the Company's income is borne by EAC.

ENP is treated as a partnership for federal and state income tax purposes with each partner being separately taxed on his share of the Partnership’s taxable income. However, in May 2006, the state of Texas enacted a new business tax (the “Texas Margin Tax”) that replaced the Texas franchise tax. The Texas Margin Tax is applicable to numerous types of entities that previously were not subject to the franchise tax. In 2006, a deferred tax liability was recognized for the expected future tax effect of the Texas Margin Tax due to the difference between the book and tax bases of the Permian Basin Assets.

On January 1, 2007, ENP adopted the provisions of Financial Accounting Standards Board (“FASB”) Interpretation No. 48, “Accounting for Uncertainty in Income Taxes — an Interpretation of FASB Statement No. 109” (“FIN 48”). FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an entity’s financial statements in accordance with SFAS No. 109, “Accounting for Income Taxes.” FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The adoption of FIN 48 did not have a material impact on the Company's consolidated balance sheet.

Revenue Recognition

     Revenues are recognized for the Company’s share of jointly owned properties as oil and natural gas is produced and sold, net of royalties. Natural gas revenues are also reduced by any processing and other fees paid, except for transportation costs paid to third parties. Natural gas revenues are recorded using the sales method of accounting, whereby revenue is recognized based on actual sales of natural gas rather than as the proportionate share of natural gas production. Royalties and severance taxes are paid based upon the actual price received from the sales. To the extent actual quantities and values of oil and natural gas are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volumes and values for those properties are estimated and recorded as accounts receivable in the accompanying Consolidated Balance Sheet. The Company does not have natural gas imbalances as it does not market its own natural gas production from wells of which it is not the operator. Encore Operating markets all the natural gas production from the wells that it operates and remits the non-operating interest owners’ share upon collection. As a result, the Company does not have any producer gas imbalances. The Company does not recognize revenue for the production in tanks, oil marketed on behalf of joint owners in the Company’s oil and natural gas properties, or oil in pipelines that has not been delivered to the purchaser. As of December 31, 2007, the Company did not have any oil inventory in pipelines.

Marketing Revenues and Expenses

     In March 2007, the Company acquired a crude oil pipeline and a natural gas pipeline from Anadarko 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, pipeline tariffs are collected for transportation through the crude oil pipeline.

     Marketing revenues includes the sales of natural gas purchased from third parties as well as pipeline tariffs charged for transportation volumes through the Company’s crude oil pipeline. Revenues derived from sales of natural gas purchased from third parties are recognized when persuasive evidence of a sales arrangement exists, delivery has occurred, the sales price is fixed or determinable, and collectibility is reasonably assured. Marketing expenses includes the cost of natural gas volumes purchased from third parties. As the Company takes title to the natural gas and has risks and rewards of ownership, these transactions are presented gross, unless they meet the criteria for netting as outlined in EITF Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty” (“EITF 04-13”). The Company did not have any marketing activities prior to 2007.

Derivatives

     The Company uses various financial instruments for non-trading purposes to manage and reduce price volatility and other market risks associated with the Company’s oil and natural gas production. These arrangements are structured to reduce the Company’s exposure to commodity price decreases, but they can also limit the benefit the Company might otherwise receive from commodity price increases. The Company’s risk management activity is generally accomplished through over-the-counter forward derivative or option contracts with large financial institutions.

     The Company applies the provisions of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” and

6

ENCORE ENERGY PARTNERS GP LLC

NOTES TO CONSOLIDATED BALANCE SHEET — (Continued)

its amendments (“SFAS 133”). SFAS 133 requires each derivative instrument to be recorded in the balance sheet as either an asset or liability measured at fair value. The Company has elected to not designate its current portfolio of derivatives as hedges and records mark-to-market gains or losses each quarter.

New Accounting Pronouncements

SFAS No. 157, “Fair Value Measurements” (“SFAS 157”)

     In September 2006, the 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. SFAS 157 is prospectively effective for financial assets and liabilities for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. 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 delays 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 Company has 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. The Company will continue to evaluate the impact of SFAS 157 on these instruments during the deferral period. SFAS 157, as it relates to financial assets and liabilities, is effective beginning in the first quarter of 2008. SFAS 157 will have an impact on the calculation and reported fair value of the Company’s derivative contracts and related disclosures; however, the Company does not expect the change to have a material impact on its Consolidated Balance Sheet.

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 is effective for fiscal years beginning after November 15, 2007. The Company adopted SFAS 159 effective January 1, 2008, and did not elect the fair value option for eligible instruments existing on that date. Therefore, the initial adoption of SFAS 159 did not have an impact on the Company’s financial condition. The Company 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 Company’s Consolidated Balance Sheet.

FSP on FASB Interpretation (“FIN”) 39-1, “Amendment of FASB Interpretation No. 39” (“FSP FIN 39-1”)

     In April 2007, the FASB issued FSP FIN 39-1. FSP FIN 39-1 amends FIN No. 39, “Offsetting of Amounts Related to Certain Contracts” (“FIN 39”), to permit a reporting entity that is party to a master netting arrangement to offset the fair value amounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) against fair value amounts recognized for derivative instruments that have been offset under the same master netting arrangement in accordance with FIN 39. FSP FIN 39-1 is effective for fiscal years beginning after November 15, 2007. The Company adopted FSP FIN 39-1 effective January 1, 2008. The adoption of FSP FIN 39-1 did not have a material impact on its Consolidated Balance Sheet.

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 Company). Early application is prohibited. The Company is evaluating the impact SFAS 141R will have on its financial

7

ENCORE ENERGY PARTNERS GP LLC

NOTES TO CONSOLIDATED BALANCE SHEET — (Continued)

condition and the reporting of future acquisitions in the Consolidated Balance Sheet.

SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements — an amendment of ARB No. 51” (“SFAS 160”)

     In December 2007, the FASB issued SFAS 160. SFAS 160 amends Accounting Research Bulletin No. 51, “Consolidated Financial Statements” to establish accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. SFAS 160 clarifies that a noncontrolling interest should be presented as a component of equity in the consolidated financial statements and requires consolidated net income to be reported at amounts that include the amounts attributable to both the parent and the noncontrolling interest. In addition, the standard establishes expanded disclosure requirements and addresses changes in a parent’s ownership of a noncontrolling interest, changes in a parent’s ownership interest while the parent retains its controlling financial interest, and fair value measurement of any retained noncontrolling interest investment. SFAS 160 is effective for financial statements issued for fiscal years beginning on or after December 15, 2008, and interim periods within those fiscal years. SFAS 160 will have a material impact on the presentation of the noncontrolling interest in ENP in the Consolidated Balance Sheet.

Note 3. Acquisition

     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. At closing, OLLC paid Anadarko approximately $328.4 million for the Elk Basin Assets. In August 2007, ENP paid an additional $0.8 million for the Elk Basin Assets as a result of customary post-closing adjustments. In October 2007, certain fixed assets were purchased from Anadarko in connection with the acquisition, resulting in an additional $0.4 million purchase price.

     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. Natural gas liquids are produced as a byproduct of the flue gas tertiary recovery project and are sold at market prices.

     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 6. Debt” for additional discussion of the Company’s long-term debt.

8

ENCORE ENERGY PARTNERS GP LLC

NOTES TO CONSOLIDATED BALANCE SHEET — (Continued)

Note 4. Commitments and Contingencies

     From time to time, the Company is a party to various legal proceedings in the ordinary course of business. The Company is not currently a party to any litigation or pending claims that it believes would have a material adverse effect on its business, financial condition, results of operations, or liquidity.

     Additionally, the Company 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 these notes.

Note 5. Asset Retirement Obligations

     The Company’s primary AROs 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 Company’s future abandonment liability, the long-term portion of which is recorded in “Future abandonment cost” on the accompanying Consolidated Balance Sheets, for 2007 (in thousands):

Future abandonment liability at January 1	$	296
Wells drilled		28
Accretion of discount		309
Plugging and abandonment costs incurred		(103	)
Revision of estimates		83
Liability assumed in Elk Basin acquisition		5,798
Future abandonment liability at December 31	$	6,411

     Approximately $4.4 million of the future abandonment liability as of December 31, 2007 represents the cost for decommissioning the Elk Basin natural gas processing plant. The Company expects to continue reserving additional amounts based on the estimated timing to cease operations of the natural gas processing plant. In addition to the future abandonment liability for the Elk Basin plant, as of December 31, 2007, the Company has recorded an estimated liability of $1.0 million related to required environmental plant compliance costs caused by past operations of the plant. The liability was assumed from Anadarko in the acquisition of the Elk Basin Assets. The liability was estimated based on directives from the Bureau of Land Management for required cleanup of environmental contamination.

Note 6. 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 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 December 31, 2007, the borrowing base was $145 million.

     The OLLC Credit Agreement matures on March 7, 2012. 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.

     Loans under the OLLC 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

9

ENCORE ENERGY PARTNERS GP LLC

NOTES TO CONSOLIDATED BALANCE SHEET — (Continued)

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 the Partnership) is the rate per year equal to the London Interbank Offered Rate (“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.

     As of December 31, 2007, the aggregate principal amount of loans outstanding under the OLLC Credit Agreement was $47.5 million and there were $0.1 million of outstanding letters of credit. Outstanding letters of credit reduce the availability under the OLLC Credit Agreement. Borrowings under the OLLC Credit Agreement may be repaid from time to time without penalty.

     On August 22, 2007, OLLC entered into an amendment to the OLLC Credit Agreement to modify certain financial covenants. The amendment did not impact any other provisions in the OLLC Credit Agreement. The covenants, as amended, 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 the assets of the Partnership, OLLC and its restricted subsidiaries, subject to permitted exceptions;

• restrictions on merging and selling assets outside the ordinary course of business;

• restrictions on use of proceeds, investments, transactions with affiliates, or change of principal business;

• a provision limiting oil and natural gas hedging transactions (other than puts) to a volume not exceeding 75 percent of anticipated production from proved producing reserves;

• a requirement that 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 OLLC 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 OLLC 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 OLLC Credit Agreement) of not more than 3.5 to 1.0.

     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 December 31, 2007, OLLC was in compliance with all debt covenants under the OLLC Credit Agreement, as amended.

     OLLC incurs a commitment fee on the unused portion of the OLLC Credit Agreement determined based on the ratio of amounts outstanding under the OLLC Credit Agreement to the borrowing base in effect on such date. The following table summarizes the calculation of the commitment fee under the OLLC 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	%

10

ENCORE ENERGY PARTNERS GP LLC

NOTES TO CONSOLIDATED BALANCE SHEET — (Continued)

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, including accrued interest, was repaid using a portion of the net proceeds from the IPO.

Long-Term Debt Maturities

     The following table illustrates the Company’s long-term debt maturities at December 31, 2007:

	Payments Due by Period
	Total		2008		2009		2010		2011		2012		Thereafter
	(in thousands)
Revolving credit facility	$	47,500	$	—	$	—	$	—	$	—	$	47,500	$	—

Note 7. Owner’s Net 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 Company 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 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 8. Unit-Based Compensation Plans” for additional discussion of the management incentive units.

     On November 14, 2007, the Partnership paid a prorated quarterly distribution of $0.053 per unit for the period from and including September 17, 2007 (the closing date of the IPO) through September 30, 2007. The total distribution of $1.3 million was paid to unitholders of record as of the close of business on November 8, 2007.

Note 8. Unit-Based Compensation Plans

Management Incentive Units

     In May 2007, the Company’s board of directors issued 550,000 management incentive units to certain executive officers of the Company. 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. A management incentive unit is also convertible into common units upon the occurrence of certain events. 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.

     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

11

ENCORE ENERGY PARTNERS GP LLC

NOTES TO CONSOLIDATED BALANCE SHEET — (Continued)

vesting will occur on the first and second anniversary of such closing date. As of December 31, 2007, ENP had $4.8 million of total unrecognized compensation cost related to unvested, outstanding management incentive units, which is expected to be recognized over a weighted average period of 0.7 years. There have not been any additional issuances or forfeitures of management incentive units since the initial issuance.

ENP Incentive Plan

     As discussed in “Note 1. Formation of the Company and Description of Business,” in connection with the IPO, the Company’s board of directors 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. As of December 31, 2007, there were 1,130,000 units available for issuance under the ENP Incentive Plan. The ENP Incentive Plan is administered by the Company’s board of directors or a committee thereof, referred to as the plan administrator.

     In October 2007, the Company’s board of directors issued 20,000 phantom units to the Company’s directors 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 123R. Accordingly, the Company determines the fair value of these awards at each reporting period, based on the closing unit price of the Partnership, and recognizes a portion of the liability as a component of other current liabilities and a portion of the liability as other noncurrent liabilities on the Consolidated Balance Sheet. As of December 31, 2007, the total liability was $31,000. 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.

     Subsequent to December 31, 2007, the Company’s board of directors issued 5,000 phantom units to a new board member pursuant to the ENP Incentive Plan. There have not been any forfeitures of phantom units. 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 9. Financial Instruments

     The carrying value of the Company’s cash, 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. Commodity derivative contracts are marked-to-market each quarter in accordance with the provisions of SFAS 133.

Derivative Financial Instruments

     The Company manages commodity price risk with swap contracts, put contracts, collars, and floor spreads. Swap contracts provide a fixed price for a notional amount of volume. Put contracts provide a fixed floor price on a notional amount of volume while allowing full price participation if the relevant index price closes above the floor price. Collar contracts provide a floor price for a notional amount of volume while allowing some additional price participation if the relevant index price closes above the floor price. Additionally, the Company occasionally sells put contracts with a strike price well below the floor price of an existing or new floor. Combined, the short floor and long floor are called a floor spread.

     In connection with the acquisition of the Elk Basin Assets, EAC purchased floor contracts for 2,500 Bbls per day (“Bbls/D”) of production at $65.00 per Bbl for April 2007 through December 2008 that were all later contributed to the Partnership at their fair market value on the date of transfer of $9.4 million. In addition to these contributed derivatives, the Company has purchased additional derivative financial instruments as part of its risk management strategy.

     The following tables summarize the Company’s open commodity derivative instruments as of December 31, 2007:

12

ENCORE ENERGY PARTNERS GP LLC

NOTES TO CONSOLIDATED BALANCE SHEET — (Continued)

Oil Derivative Contracts

																		Asset
	Daily		Average		Daily			Average		Daily		Average		Daily		Average		(Liability)
	Floor		Floor		Short Floor			Short Floor		Cap		Cap		Swap		Swap		Fair Market
Period	Volume		Price		Volume			Price		Volume		Price		Volume		Price		Value
	(Bbl)		(per Bbl)		(Bbl)			(per Bbl)		(Bbl)		(per Bbl)		(Bbl)		(per Bbl)		(in thousands)
Jan. 2008		2,500	$	65.00		(2,000	)	$	65.00		—	$	—		—	$	—	$	—
		2,000		75.00		—			—		—		—		—		—
Feb. — Dec. 2008		880		80.00		—			—		440		107.60		—		—		930
		2,000		75.00		—			—		—		—		—		—
		2,500		65.00		(2,000	)		65.00		—		—		—		—
2009		880		80.00		—			—		440		97.75		—		—		(3,050	)
		2,250		75.00		—			—		—		—		—		—
		1,250		63.40		(1,250	)		65.00		—		—		1,000		68.70
2010		880		80.00		—			—		440		93.80		—		—		52
		2,000		75.00		—			—		1,000		77.23		—		—
		2,000		65.00		(2,000	)		65.00		—		—		—
2011		1,000		80.00		—			—		1,000		94.65		—		—		1,811
		1,000		70.00		—			—		—		—		—		—
		1,000		70.00		—			—		—		—		—		—
																		$	(257	)

Natural Gas Derivative Contracts

	Daily		Average		Daily		Average		Asset
	Floor		Floor		Cap		Cap		Fair Market
Period	Volume		Price		Volume		Price		Value
	(Mcf)		(per Mcf)		(Mcf)		(per Mcf)		(in thousands)
Jan. 2008		2,000	$	8.20		2,000	$	9.85	$	119
		2,000		7.20		—		—
Feb. — Dec. 2008		3,800		8.20		3,800		9.83		1,798
		3,800		7.20		—		—
2009		3,800		8.20		3,800		9.83		1,376
		3,800		7.20		—		—
2010		3,800		8.20		3,800		9.58		1,240
		3,800		7.20		—		—
									$	4,533

     Commodity Contracts – Mark-to-Market Accounting: Floor Spreads. In order to partially finance the cost of premiums on certain purchased floors, the Company 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. During 2007, the Company entered into floor spreads with a $75 per Bbl purchased floor and a $65 per Bbl short floor for 2,000 Bbls/D in 2008 and 2010 and 1,250 Bbls/D in 2009. As with the Company’s other derivative contracts, these are marked-to-market each quarter. In the above table, the purchased floor component and the short floor component of these floor spreads has been included with the Company’s other floor contracts and the short floor component is shown separately as negative volumes. The net cash flows per Bbl upon settlement of the contracts and payment of the related premiums when viewed together change depending on the NYMEX oil price as follows:

• When the NYMEX oil price is greater than $75 per Bbl, the Company pays the net purchased floor premium cost per Bbl.

• When the NYMEX oil price is greater than $65 per Bbl but less than $75 per Bbl, the Company receives settlements of $75 per Bbl less the NYMEX oil price and pays the net purchased floor premium cost per Bbl.

• When the NYMEX oil price is below $65 per Bbl, the Company receives $10 per Bbl less the net purchased floor premium cost per Bbl.

     Counterparty Risk. At December 31, 2007, the Company had committed greater than 10 percent of either its oil or natural gas production represented by derivative contracts to the following counterparties:

13

ENCORE ENERGY PARTNERS GP LLC

NOTES TO CONSOLIDATED BALANCE SHEET — (Continued)

	Percentage of			Percentage of
	Oil Derivative			Natural Gas
	Contracts			Derivative Contracts
Counterparty	Committed			Committed
Bank of America, N.A.		37.6	%		—
BNP Paribas		40.4	%		23.3	%
Calyon		5.7	%		17.8	%
Wachovia		2.5	%		58.9	%

     The Company believes the credit-worthiness of its counterparties is sound and does not anticipate any non-performance of contractual obligations. As long as each counterparty maintains an investment grade credit rating, pursuant to ENP’s derivative contracts, no collateral is required.

     In order to mitigate the credit risk of financial instruments, ENP enters into master netting agreements with significant counterparties. The master netting agreement is a standardized, bilateral contract between a given counterparty and ENP. Instead of treating separately each financial transaction between the counterparty and ENP, the master netting agreement enables the counterparty and ENP to aggregate all financial trades and treat them as a single agreement. This arrangement benefits ENP in three ways: (i) the netting of the value of all trades reduces the requirements of daily collateral posting by ENP, (ii) default by a counterparty under one financial trade can trigger rights to terminate all financial trades with such counterparty, and (iii) netting of settlement amounts reduces ENP’s credit exposure to a given counterparty in the event of close-out.

Note 10. Related Party Transactions

     The Company does not have any employees. The employees supporting the operations of the Company are employees of EAC. As discussed in “Note 1. Formation of the Partnership and 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. Under the Administrative Services Agreement, Encore Operating receives an administrative fee of $1.75 per BOE of the Partnership’s production for such services and reimbursement for actual third-party expenses incurred on the Partnership’s behalf. The Partnership also pays its share of expenses that are directly chargeable to wells under joint operating 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. 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. In 2007, the Partnership paid $2.8 million to Encore Operating for administrative fees under the Administrative Services Agreement (including payment of any COPAS recovery) and $3.5 million for reimbursement of actual third-party expenses incurred on the Partnership’s behalf. As of December 31, 2007, the Partnership had a payable to EAC of $1.4 million for services provided by Encore Operating, which is reflected in “Accounts payable – affiliate” in the accompanying Consolidated Balance Sheet. As of December 31, 2007, the Partnership had a receivable from EAC of $0.7 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.

     On November 14, 2007, the third quarter distribution was paid to unitholders at a rate of $0.053 per unit, which was based on an initial quarterly distribution of $0.35 per unit, prorated from the period from and including September 17, 2007 (the closing date of the IPO) through September 30, 2007. The Partnership distributed approximately $0.7 million to EAC as holders of 14,039,279 million common units and approximately $27,000 to the Company as the holder of 504,851 general partner units.

     As discussed in “Note 6. Debt” of these consolidated financial statements, the Partnership used a portion of the net proceeds from the IPO to repay in full the subordinated credit agreement held by a related party of the Partnership.

     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.

14

ENCORE ENERGY PARTNERS GP LLC

NOTES TO CONSOLIDATED BALANCE SHEET – (Continued)

Note 11. Subsequent Events

Purchase and Investment Agreement

     On December 27, 2007, OLLC entered into a purchase and investment agreement (the “Purchase Agreement”) with Encore Operating. Pursuant to the agreement, OLLC acquired certain oil and natural gas producing properties and related assets in the Permian and Williston Basins. The transaction closed on February 7, 2008 and was effective January 1, 2008.

     The total consideration for the acquisition consisted of $125.4 million in cash and 6,884,776 common units representing limited partner interests in the Partnership. Upon completion of the acquisition, the borrowing base under OLLC’s revolving credit facility was increased to $240 million. OLLC financed the cash portion of the purchase price through additional borrowings under the OLLC Credit Agreement.

     The acquisition will be accounted for as a transaction between entities under common control. Therefore, the assets will be recorded on the Partnership’s balance sheet at EAC’s historical basis, and the historical results of operations of the Partnership will be restated to reflect the historical operating results of the combined entities.

Commodity Derivative Contracts

     Subsequent to December 31, 2007, the Company increased its oil derivative contract positions by entering into additional commodity derivative contracts. The following tables summarize the Company’s open commodity derivative contracts as of February 20, 2008:

Oil Derivative Contracts

	Daily		Average		Daily			Average		Daily		Average		Daily		Average
	Floor		Floor		Short Floor			Short Floor		Cap		Cap		Swap		Swap
Period	Volume		Price		Volume			Price		Volume		Price		Volume		Price
	(Bbl)		(per Bbl)		(Bbl)			(per Bbl)		(Bbl)		(per Bbl)		(Bbl)		(per Bbl)
2008		880		$80.00		—		$	—		440	$	107.60		—	$	—
		2,000		75.00		—			—		—		—		—		—
		2,500		65.00		(2,000	)		65.00		—		—		—		—
2009		880		80.00		—			—		440		97.75		—		—
		2,250		75.00		—			—		—		—		—		—
		1,250		63.40		(1,250	)		65.00		—		—		1,000		68.70
2010		880		80.00		—			—		440		93.80		—		—
		2,000		75.00		—			—		1,000		77.23		—		—
		2,000		65.00		(2,000	)		65.00		—		—		—		—
2011		1,880		80.00		—			—		1,440		95.41		—		—
		1,000		70.00		—			—		—		—		—		—

Natural Gas Derivative Contracts

	Daily		Average		Daily		Average
	Floor		Floor		Cap		Cap
Period	Volume		Price		Volume		Price
	(Mcf)		(per Mcf)		(Mcf)		(per Mcf)
2008		3,800		$8.20		3,800		$9.83
		3,800		7.20		—		—
2009		3,800		8.20		3,800		9.83
		3,800		7.20		—		—
2010		3,800		8.20		3,800		9.58
		3,800		7.20		—		—

Other Events

     On January 21, 2008, the Partnership declared a distribution for the fourth quarter of 2007 to unitholders of record as of the close of business on February 6, 2008. Approximately $9.8 million was paid on February 14, 2008 to unitholders at a rate of $0.3875 per unit.

     On February 4, 2008, the Partnership entered into interest rate swaps whereby the Partnership swapped $100 million of floating rate debt to a weighted average fixed rate of 3.06 percent. As discussed in “Note 6. Debt,” loans under the OLLC Credit Agreement are subject to a margin in addition to the Eurodollar or base rate of interest, determined 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. Interest determined in accordance with the applicable margin is in addition to the fixed rate entered into in the interest rate swap agreements.

15

ENCORE ENERGY PARTNERS GP LLC

SUPPLEMENTARY INFORMATION

Capitalized Costs and Costs Incurred Relating to Oil and Natural Gas Producing Activities

     The capitalized cost of oil and natural gas properties was as follows as of December 31, 2007 (in thousands):

Properties and equipment, at cost — successful efforts method:
Proved properties, including wells and related equipment	$	378,170
Accumulated depletion, depreciation, and amortization		(37,661	)
	$	340,509

     The following table summarizes costs incurred related to oil and natural gas properties for the year ended December 31, 2007 (in thousands):

Acquisitions:
Proved properties	$	326,751
Asset retirement obligations		5,798
Total acquisitions		332,549
Development:
Drilling and exploitation		8,887
Asset retirement obligations		28
Total development		8,915
Total costs incurred	$	341,464

Oil & Natural Gas Producing Activities — Unaudited

     The estimates of the Partnership’s proved oil and natural gas reserves, which are located entirely within the United States, were prepared in accordance with guidelines established by the Securities and Exchange Commission (“SEC”) and the FASB. Proved oil and natural gas reserve quantities are derived from estimates prepared by Miller and Lents, Ltd., who are independent petroleum engineers.

     Future prices received for production and future production costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. There can be no assurance that the proved reserves will be developed within the periods assumed or that prices and costs will remain constant. Actual production may not equal the estimated amounts used in the preparation of reserve projections. In accordance with SEC guidelines, estimates of future net cash flows from ENP’s properties and the representative value thereof are made using oil and natural gas prices in effect as of the dates of such estimates and are held constant throughout the life of the properties. Year-end prices used in estimating net cash flows were as follows as of December 31, 2007:

Oil (per Bbl)	$	96.01
Natural gas (per Mcf)		7.47

     Net future cash inflows have not been adjusted for commodity derivative contracts outstanding at the end of the year. The future cash flows are reduced by estimated production costs and development costs, which are based on year-end economic conditions and held constant throughout the life of the properties, and by the estimated effect of future income taxes due to the Texas margin tax. Future federal income taxes have not been deducted from future net revenues in the calculation of the Partnership’s standardized measure as each partner is separately taxed on his share of the Partnership’s taxable income.

     There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures. Oil and natural gas reserve engineering is and must be recognized as a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in any exact way, and estimates of other engineers might differ materially from those included herein. The accuracy of any reserve estimate is a function of the quality of available data and engineering, and estimates may justify revisions based on the results of drilling, testing, and production activities. Accordingly, reserve estimates are often materially different from the quantities of oil and natural gas that are ultimately recovered. Reserve estimates are integral to management’s analysis of impairments of oil and

16

ENCORE ENERGY PARTNERS GP LLC

SUPPLEMENTARY INFORMATION — (Continued)

natural gas properties and the calculation of DD&A on these properties.

     Estimated net quantities of proved oil and natural gas reserves of the Partnership were as follows as of December 31, 2007:

Proved reserves:
Oil (MBbls)	14,417
Natural gas (MMcf)	39,140
Combined (MBOE)	20,940
Proved developed reserves:
Oil (MBbls)	12,983
Natural gas (MMcf)	30,515
Combined (MBOE)	18,069

     The changes in proved reserves were as follows for 2007:

				Natural			Oil
	Oil			Gas			Equivalent
	(MBbls)			(MMcf)			(MBOE)
Balance, December 31, 2006		50			37,426			6,288
Acquisitions of minerals-in-place		15,330			2,359			15,724
Extensions and discoveries		70			1,140			260
Revisions of previous estimates		20			84			33
Production		(1,053	)		(1,869	)		(1,365	)
Balance, December 31, 2007		14,417			39,140			20,940

17

ENCORE ENERGY PARTNERS GP LLC

SUPPLEMENTARY INFORMATION — (Continued)

     The standardized measure of discounted estimated future net cash flows related to proved oil and natural gas reserves was as follows as of December 31, 2007 (in thousands):

Future cash inflows	$	1,348,498
Future production costs		(473,800	)
Future development costs		(28,626	)
Future abandonment costs, net of salvage		(20,266	)
Future income tax expense		(4,989	)
Future net cash flows		820,817
10% annual discount		(382,456	)
Standardized measure of discounted estimated future net cash flows	$	438,361

     The primary changes in the standardized measure of discounted estimated future net cash flows were as follows for 2007 (in thousands):

Standardized measure, beginning of year	$	50,672
Net change in prices and production costs		17,831
Purchases of minerals-in-place		426,355
Extensions, discoveries, and improved recovery		5,410
Revisions of previous quantity estimates		689
Production, net of production costs		(65,763	)
Development costs incurred during the period		8,887
Accretion of discount		5,067
Change in estimated future development costs		(11,378	)
Net change in income taxes		(1,895	)
Change in timing and other		2,486
Net increase (decrease)		387,689
Standardized measure, end of year	$	438,361

18